56177126 Underground Distribution System Design Guide

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Underground DistributionSystem Design Guide

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P R O J E C T 0 3 - 0 8

Prepared by

Edward S. Thomas, PEUtility Electrical Consultants, PC

620 N.West St., Suite 103Raleigh, NC 27603-5938

and

Bill DorsettBooth & Associates, Inc.

1011 Schaub DriveRaleigh, NC 27606

for

Cooperative Research NetworkNational Rural Electric Cooperative Association

4301 Wilson BoulevardArlington, Virginia 22203-1860

Underground DistributionSystem Design Guide

The National Rural Electric Cooperative AssociationThe National Rural Electric Cooperative Association (NRECA), founded in 1942, is the national service organization supportingmore than 900 electric cooperatives and public power districts in 47 states. Electric cooperatives own and operate more than42 percent of the distribution lines in the nation and provide power to 40 million people (12 percent of the population).

© Underground Distribution System Design GuideCopyright © 2008, by the National Rural Electric Cooperative Association.Reproduction in whole or in part is strictly prohibited without prior written approval of the National Rural Electric CooperativeAssociation, except that reasonable portions may be reproduced or quoted as part of a review or other story about thispublication.

Legal NoticeThis work contains findings that are general in nature. Readers are reminded to perform due diligence in applying thesefindings to their specific needs, as it is not possible for NRECA to have sufficient understanding of any specific situationto ensure applicability of the findings in all cases.

Neither the authors nor NRECA assume liability for how readers may use, interpret, or apply the information, analysis,templates, and guidance herein or with respect to the use of, or damages resulting from the use of, any information,apparatus, method, or process contained herein. In addition, the authors and NRECA make no warranty or representationthat the use of these contents does not infringe on privately held rights.

This work product constitutes the intellectual property of NRECA and its suppliers, as the case may be, and containsConfidential Information. As such, this work product must be handled in accordance with the CRN Policy Statementon Confidential Information.

Contact:

Edward S. Thomas, PEUtility Electrical Consultants, PC620 N.West St., Suite 103Raleigh, NC 27603-5938Phone: 919.821.1410Fax: 919.821.2417

Bill DorsettBooth & Associates, Inc.1011 Schaub DriveRaleigh, NC 27606Phone: 919.851.8770Fax: 919.859.5918

Contents – i i i

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Section 1 Design of an Underground Distribution System 1System Components 2Types of UD Systems 6Reliability of UD Systems 14Design Considerations for System Operation and Maintenance 17Future Upgrades and Replacements 19Economic Comparison of System Configurations 20UD Loss Economics 32Steps for Layout of a UD System 38Summary and Recommendations 50

Section 2 Cable Selection 51Typical Cable Configuration 51Conductor Size Designations 53Conductor Materials and Configuration 53Cable Insulation Materials 57Insulation Fabrication 60Conductor Shields and Insulation Shields 64Cable Specification and Purchasing 74Cable Acceptance 77Summary and Recommendations 77

Section 3 Underground System Sectionalizing 79General Sectionalizing Philosophy 79Overcurrent Protection of Cable System 88Effect of Inrush Current on Sectionalizing Devices 96Selection of Underground Sectionalizing Equipment 100Faulted-Circuit Indicators 105Summary and Recommendations 118

Section 4 Equipment Loading 121Primary Cable Ampacity 121Pad-Mounted Transformer Sizing 144Summary and Recommendations 163

Section 5 Grounding and Surge Protection 165Cable Grounding System Function 166Factors Affecting Cable Grounding System Performance 177Counterpoise Application for Insulated Jacketed Cable 188System Ground Resistance Measurement and Calculation 192Underground System Surge Protection 207Summary and Recommendations 236

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Section 6 Ferroresonance 239Allowable Overvoltages During Ferroresonance 240Distribution Transformer Connections 241Qualitative Description of Ferroresonance 242Ferroresonance When Switching at the Primary Terminals of Overhead

and Underground Transformer Banks 252Ferroresonance with Cable-Fed Three-Phase Transformers with Delta

or Ungrounded-Wye Connected Primary Windings 254Ferroresonance with Cable-Fed Three-Phase Transformers with

Grounded-Wye Primary Winding and Five-Legged Core 260Ferroresonance with Cable-Fed Three-Phase Transformers with

Grounded-Wye Primary Windings and Triplex Construction 266Ferroresonance in Underground Feeders Having More Than

One Transformer 270Summary of Techniques for Preventing Ferroresonance in

Underground Systems 273Summary and Recommendations 276References 279

Section 7 Cathodic Protection Requirements 281Special Note 281Introduction 281What to Protect 282Where to Protect 282Types of Cathodic Protection Systems 285Amount of Cathodic Protection 286Cathodic Protection Design with Galvanic Anodes 287Cathodic Protection Installation and Follow-Up 294Calculation of Resistence to Ground 296Summary and Recommendations 297

Section 8 Direct-Buried System Design 299Trench Construction Considerations 299Trench Design Components 300Trench Layout/Routing Considerations 303Depth of Burial 304Joint-Occupancy Trenches 307Summary and Recommendations 309

Section 9 Conduit System Design 311Conduit System Design 311Cable Pulling 332Summary and Recommendations 341

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Section 10 Joints, Elbows, and Terminations 343Joints, Elbows, and Terminations for 200-Ampere Primary Circuits 344Joints, Elbows, and Terminations for 600-Ampere Primary Circuits 353Joints, and Terminations for Secondary Circuits 355Summary and Recommendations 357

Section 11 Cable Testing 359Reasons for and Benefits of Cable Testing by the User 359Primary Cable Tests by the User 359Secondary Cable Tests by the User 369Tests by the Cable Manufacturer 370Summary and Recommendations 372

Appendix A Calculations for Reliability Studies 373Reliability Index 373Acceptability Criteria 374Calculation of Reliability 374Importance of Sectionalizing 375

Appendix B Transformer and Secondary Voltage Drop 377Voltage Flicker 385

Appendix C Sample Specification UGC2 for 600-VoltSecondary Underground Power Cable 389Scope 389General Specifications 390Referenced Specifications 390Conductor 391Insulation 391Tests 392Miscellaneous 393Markings 393Multiconductor Cable Assemblies 393

Appendix D Checklist for Information Requirements 395Project Information Checklist 395

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Appendix E Sample Specification for 15-, 25-, and 35-kV Primary UndergroundMedium Voltage Concentric Neutral Cable (Specification UGC1) 397Purpose 397General Specifications 397Referenced Specifications 398Conductor 399Conductor Shield (Stress Control Layer) 400Insulation 400Insulation Shielding 400Concentric Neutral Conductor 401Overall Outer Jacket 401Dimensional Tolerances 402Tests 402Miscellaneous 403

Appendix F Allowable Short Circuit Currents for Solid Dielectric Insulated Cables 405

Appendix G Ampacity Tables 415

Appendix H Industry Specifications 425

Appendix I Component Manufacturers 427

Appendix J Cable-Pulling Examples 431

Abbreviations 435

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1.1 UD System Components 21.2 Schematics for Different Types of Switchgear 31.3 Flat Pad for Equipment Mounting 51.4 Ground Sleeve 51.5 Box Pad for Equipment Mounting 51.6 Underground Substation Circuit Exit 61.7 Radial Main Feeder 71.8 Radial Main Feeder with Faulted Cable Section 81.9 Open-Loop Feeder 91.10 Open-Loop Feeder with Faulted Cable Section 91.11 Radial Feeder 101.12 Open-Loop Feeder in Shopping Center 111.13 Multiple-Loop System 111.14 Area Lighting System 121.15 Loop-Feed Design of UD System Under Normal Conditions 161.16 Loop-Feed Design of UD System with Damaged Cable Section 161.17 Open-Loop System, 37-Lot Subdivision 211.18 Open-Loop System, Single Residential Consumer 221.19 Single-Phase Sub-Feeder 241.20 Three-Phase Sub-Feeder 251.21 Front Property Placement 281.22 Back Property Placement 281.23 Methods for Providing Secondary Service 311.24 Road Crossing to Feed Secondary Pedestal 401.25 Service and Transformer Layout for 75-Lot Subdivision 401.26 Primary Cable Layout for 75-Lot Subdivision 421.27 Minimum Required Working Space 431.28 Sample Easement 471.29 Staking Sheet for Service to a Commercial Consumer 49

2.1 Jacketed Concentric Neutral Cable 522.2 Bare Concentric Neutral Cable 522.3 Medium-Voltage Power Cable with Tape Shield and L.C. Shield 522.4 Concentric Lay Strand Options 562.5 Standard Strand Arrangements for Multilayer Conductors 562.6 Comparative Hot Creep vs. Temperatures for Cable Insulation Materials 602.7 General Layout of a Cable Extrusion Line 622.8 Typical Extrusion Methods 632.9 Capacitive and Dielectric Loss Current Flow in Insulation Shield 662.10 Cable Identification Markings 73

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3.1 Symmetrical Current 823.2 Asymmetrical Short-Circuit Current 823.3 Sample Distribution Circuit with Typical Locations of Sectionalizing

Devices Show 863.4 Cross Section of Cable Showing Components Subject to

Through-Fault Damage 883.5 Example of 70-Ampere, Type “L” Recloser Curves for Cable Protection 903.6 Current Limiting Fuses for Padmounted Switching Cabinets 1043.7 Inrush Current Resulting from Operation of Three-Phase Recloser 1073.8 Inrush Current Resulting from Operation of Single-Phase Recloser 1073.9 Trip Response for Peak-Current-Sensitive Units 1083.10 Trip Response for 450A and 800A FCIs 1093.11 Trip-Set Characteristics for Adaptive-Trip FCI 1103.12 FCI Placement on Overhead Feeder with Underground Segment 1113.13 FCI Placement on Three-Phase Underground Feeder 1113.14 FCI Placement for Single-Phase Open Loop 1123.15 FCI Placement for Underground Subdivision with Three-Phase Source 1123.16 Current-Reset FCI 1133.17 Low-Voltage-Reset FCI 1143.18 High-Voltage-Reset FCI 1143.19 Time-Reset FCI 1153.20 Correct Placement of FCI Sensor 1163.21 Incorrect Placement of FCI Sensor 1163.22 Reset FCI 117

4.1 Ratio of Shield Loss to Conductor DC Loss at 90°C as a Functionof Shield Resistance, 1/C 35-kV Aluminum Power Cables inTriplexed Formation 124

4.2 Relationship Between Load Factor and Loss Factor Per Unit 1254.3 Thermal Resistivity vs. Moisture Content for Various Soil Types 1274.4 Thermal Resistivity of Soil at Various Locations 1274.5 Effect of Depth on Soil Temperatures as Influenced by Seasonal

Temperature Variations 1284.6 Trefoil or Triangular Cable Configuration 1304.7 Flat Conductor Configuration, Maintained Spacing 1304.8 Direct-Buried Duct Bank Installation Using Rigid Nonmetallic Conduit 1324.9 Single-Phase U-Guard Installation with Vented Base 1364.10 Three-Phase Cable Installation Configurations 138, 4234.11 Typical Dead-Front, Single-Phase, Pad-Mounted Transformer 1454.12 Actual Load Cycle and Equivalent Load Cycle 1474.13 Thermal Equivalent Load Cycle 1474.14 Case Temperature Measurement Location—Pad-Mounted Distribution

Transformer 1594.15 Relationship Among NEMA Starting Code Letters, Starts per Hour, and

Transformer kVA per Motor HP for Transformer Thermal Considerations 1604.16 Maximum Motor Starts per Hour for Transformer Mechanical Considerations 162

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5.1 Typical Distribution Transformer Core Form Design and NeutralGrounding Circuit 169

5.2 Variation of Surge Impedance with Surge Current for Various Valuesof 60-Cycle Resistance 171

5.3 Surge Characteristics of Various Ground Rods 1715.4 Arrester Lead Length for Two Riser Pole Installations 1735.5 Three-Phase Installation Showing Optimum Riser Pole Arrester

Lead Connections 1735.6 Typical Primary and Secondary Underground Installation 1745.7 Schematic Diagram Showing Surge Current Paths After Lightning

Arrester Discharge 1755.8 Maximum Jacket Voltage (Neutral to Ground) Produced by Lightning

Current Surge in Ground Rod 1755.9 BCN Cable Riser Pole Installation Surge Arrester Discharge Paths 1785.10 Ground Rod Being Driven by Hydraulic Tool 1805.11 Resistance of Vertical Ground Rods as a Function of Length

and Diameter 1815.12 Resistance of Multiple Ground Rods 1825.13 Installation of Three Rods for a Riser Pole Ground 1835.14 Installation of Four Rods for a Riser Pole Ground 1835.15 Grounding Assembly for Pad-Mounted Single-Phase Transformers 1855.16 Grounding Grid for Pad-Mounted Equipment Installation 1855.17 Installation of JCN Connection in Above-Grade Pedestal 1865.18 Grounding Assembly for JCN Underground Primary Cable 1875.19 Intermediate Grounding Assembly, Underground Primary Cable 1875.20 Counterpoise 60-Hz Resistance Variation with Length and Different

Soil Resistivities 1885.21. Effect of Length on Transient Surge Impedance of Counterpoise 1895.22 Counterpoise Application to Reduce Jacket Voltage 1905.23 Earth Resistance 1935.24 Correct Ground Resistance Test Setup 1935.25 Incorrect Ground Resistance Test Setup 1935.26 Clamp-On Ground Resistance Tester 1955.27 Circuit Diagram for Multigrounded System 1955.28 Ground Resistance Test Setup for Clamp-On Tester 1955.29 Setup for Soil Resistivity Test 1965.30 Effects of Moisture on Soil Resistivity 1985.31 Effects of Salt Content on Resistivity in Soil Containing

30 Percent Moisture 1985.32 Coefficient K1 for Ground Resistance Calculations 2015.33 Grouping of Four Ground Rods with 16-Foot Spacing 2035.34 Grouping of Four Ground Rods with 5-Foot Spacing 2035.35 Types of Arresters and Their Construction 2085.36 Comparison of Nonlinear Characteristics of SiC and MOV Valve Elements 2095.37 Effect of Fast Rise Times on IR Discharge 2105.38 Series- and Shunt-Gapped MOV Distribution Arresters 210

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5.39 Dead-Front Arrester Elbow Configuration 2115.40 Dead-Front Surge Arresters 2125.41 Temporary 60-Hz Overvoltage Capability Curves—Typical MOV

Distribution Arrester 2155.42 Typical Test Current Waveshape—Sinusoidal Wavefront 2175.43 Lightning Rise Time to Peak 2185.44 Arrester Lead Length Equal to Three Feet 2195.45 Arrester Lead Length Equal to 1.5 Feet 2205.46 Zero Arrester Lead Length 2215.47 Representation of Distributed Parameter Distribution Line 2225.48 Change in Surge Impedance at a Junction Point—Effect on Traveling

Voltage Wave 2235.49 Traveling Wave Behavior at Junction Points Terminated with Various

Surge Impedances 2245.50 Traveling Waves at a Cable Open-End Point Terminated by an

MOV Arrester 2255.51 Arrester Locations 2275.52 Cable-End Arresters at Open Point 2305.53 Arrester Upstream from Open Point (Third Arrester) 2315.54 Two Elbow Arresters and a Feed-Through 2315.55 Elbow Arrester and Parking Stand Arrester 2325.56 Bushing Arrester and Parking Stand Arrester 2325.57 Elbow Arrester on Feed-Through Insert on Transformer Upstream

from Open Point 2325.58 Bushing Arrester on Transformer Upstream from Open Point 2325.59 Lateral Tap Cable-End Arrester (Radial Feed Circuit) 2325.60 Tap-Point Arrester 2325.61 Typical Underground Subdivision Loop Feed with Open Point 232

6.1 Transformer Connections for Four-Wire Wye and Four-WireDelta Services 242

6.2 Series RLC Circuit with Sinusoidal Excitation 2436.3 Cable-Fed Three-Phase Transformer Susceptible to Ferroresonance 2456.4 Conductor Spacings for an Overhead Line on an Eight-Foot Crossarm 2476.5 Equivalent Capacitance Network for an Overhead Multigrounded

Neutral Line 2476.6 Cross Section of a Multiwire Concentric Neutral Cable 2486.7 Floating-Wye/Delta Transformer Bank with Fused Cutouts at

Primary Terminals 2536.8 Three-Phase Cable-Fed Transformer with a Delta-Connected

Primary Winding 2556.9 Voltage and Current Waveforms During Ferroresonance with

a 150-kVA Delta Grounded-Wye Bank 2556.10 Five-Legged Wound-Type Core with Grounded-Wye Primary Windings 2606.11 Three-Phase Cable-Fed Transformer with a Grounded-Wye Primary

Winding on a Five-Legged Core 262

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6.12 Open-Phase Voltage Waveforms with Five-Legged CoreGrounded-Wye Transformers 262

6.13 Overhead System Supplying a Cable-Fed Grounded-WyeTransformer on a Five-Legged Core 267

6.14 Triplex-Type Wound Core with Grounded-Wye Primary Windings 2696.15 Cable-Fed Triplex-Core Transformer with Grounded-Wye

Primary Windings 2696.16 Circuit with “S” Cable Sections and “N” Five-Legged Core

Grounded-Wye Primary Transformers 2706.17 Circuit Configuration for Switching Example 6.2 2716.18 Single-Line Diagram of a Portion of a UD System 274

7.1 Dissimilar Metal Effects Between Buried Metals Connected to theNeutral of an Electric Distribution Line 282

7.2 Electric System Map Shaded to Show Corrosive Soil Locations 2837.3 Measurement of Potential to a Copper-Copper Sulfate Half Cell 2837.4 Dissimilar Metal Effects Between Copper and Steel 2847.5 Dissimilar Soil Effects on Buried Copper Wires 2847.6 Measurement of Earth Resistivity with a Four-Terminal Ground Tester 2847.7 Potentials of a Copper-Steel Couple Before and After Connecting

a Zinc Anode 2857.8 Equivalent Circuit for a Galvanic Anode Connected to the Electric Neutral 2877.9 Anode Positioning 2957.10 Anode Connector 2957.11 Test Station Connector 295

8.1 Typical Trench Warning Tape 3018.2 Cable Route Marker 3028.3 Burial Depth Requirements 3058.4 Joint Trench Use 308

9.1 Typical Duct Configurations 3169.2 Typical Duct Line and Manhole Arrangement 3199.3 Typical Arrangements for System in Figure 9.2 3199.4 Preferred Location of Duct Lines in Roadways 3269.5 Typical Manhole Configurations 326

9.6 Rectangular Manhole Construction Details 3279.7 Rectangular Manhole Installation Details 3289.8 Octagonal Manhole Construction Details 3299.9 Octagonal Manhole Installation Details 3309.10 Cable/Conduit Friction and Pulling Tension 3339.11 Cable Configurations in Conduit 3349.12 Sidewall Bearing Pressure 336

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10.1 Voltage Stress Concentration 34410.2 Voltage Stress Distribution in a Typical Premolded Joint Housing 34410.3 Premolded Permanent Straight Joint for Primary Cables 34510.4 Jacket Replacement Assembly (Method C) 34610.5 Premolded Permanent Wye Joint for Primary Cables 34710.6 Dead-Break Elbow for Primary Cables 34810.7 Load-Break Elbow for Primary Cables 34810.8 Typical 200-Ampere Elbow Accessories 34910.9 Heat-Shrink Jacket Seal at Elbow 34910.10 Premolded Indoor Termination (Slip-On Stress Cone) for Primary Cables 35110.11 Premolded Integral Indoor/Outdoor Termination for Primary Cables 35110.12 Premolded Modular Indoor/Outdoor Termination with Separate Skirts

for Primary Cables 35110.13 Porcelain Indoor/Outdoor Terminal for Primary Cables 35210.14 Cold-Shrink Indoor/Outdoor Termination for Primary Cables 35210.15 Stick-Operable, Dead-Break Elbows 35310.16 Dead-Break 600-Ampere Elbow Connector and Accessories for

Primary Cables 35410.17 Housing Assembly Joint for Secondary Cables 35510.18 Cold-Shrink Joint for Secondary Cables 35510.19 Heat-Shrink Joint for Secondary Cables 35510.20 Sealed Stud Termination for Secondary Cables 35610.21 Bus and Rubber Cover Termination for Secondary Cables 35610.22 Housing and Sleeve Assembly Termination for Secondary Cables 356

11.1 Test Setup for the Hot Silicone Oil Test 36411.2 Typical Test Setup for the Stripping Test of the Insulation Shield 36511.3 Typical High-Voltage Proof Tester Showing a Sectionalized Discharge

Stick for Grounding the Cable 368

A.1 Components Affecting Outage Rate to the Consumer 374A.2 Sectionalized UD Area 376

B.1 Distance for Various Conductor Arrangements 381B.2 Permissible Voltage Flicker Limits 386

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F.1 Aluminum Conductor/Thermoplastic Insulation (PE/HMWPE)—Allowable Short Circuit Currents Based on 75°C Initial ConductorTemperature and 150°C Final Temperature 406

F.2 Copper Conductor/Thermoplastic Insulation (PE/HMWPE)—Allowable Short Circuit Currents Based on 75°C Initial ConductorTemperature and 150°C Final Temperature 407

F.3 Aluminum Conductor/Thermoset Insulation (TR-XLPE/EPR)—Allowable Short Circuit Currents Based on 90°C Initial ConductorTemperature and 250°C Final Conductor Temperature 408

F.4 Copper Conductor/Thermoset Insulation (TR-XLPE/EPR)—Allowable Short Circuit Currents for 90°C Rated InsulationBased on 90°C Initial Conductor Temperature and 250°C FinalConductor Temperature 409

F.5 Aluminum Conductor/Thermoplastic Insulation (PE/HMWPE)—Allowable Short Circuit Currents for Conductor to Not ExceedInsulation Emergency Operating Temperature Rating Basedon 75°C Initial Conductor Temperature and 90°C FinalConductor Temperature 410

F.6 Copper Conductor/Thermoplastic Insulation (PE/HMWPE)—Allowable Short Circuit Currents for Conductor to Not ExceedInsulation Emergency Operating Temperature Rating Basedon 75°C Initial Conductor Temperature and 90°C FinalConductor Temperature 411

F.7 Aluminum Conductor/Thermoset Insulation (TR-XLPE/EPR)—Allowable Short Circuit Currents for Conductor to Not ExceedInsulation Emergency Operating Temperature Rating Basedon 90°C Initial Conductor Temperature and 130°C FinalConductor Temperature 412

F.8 Copper Conductor/Thermoset Insulation (TR-XLPE/EPR)—Allowable Short Circuit Currents for Conductor to Not ExceedInsulation Emergency Operating Temperature Rating Basedon 90°C Initial Conductor Temperature and 130°C FinalConductor Temperature 413

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1.1 Lamp and Ballast Characteristics—240 Volts 141.2 Front Versus Rear Property Line Placement 171.3 Additional Materials for an Open-Loop System 201.4 Sample Spare Cable Cost, Single Residential Consumer 221.5 Sample Radial System Cost, Commercial Consumer 231.6 Additional Cost per Kilowatt, Open-Loop and Spare Cable Systems 231.7 Single-Phase Sub-Feeder Cost 241.8 Three-Phase Sub-Feeder Cost 251.9 25-kV Versus 15-kV Cable and Components 261.10 Added Cost of Dual-Voltage Transformers 261.11 Voltage Conversion Cost at Year 10 261.12 Voltage Conversion Cost at Year 20 271.13 Option 1—Direct-Buried Cable 301.14 Option 2—PVC Rigid Conduit 301.15 Option 3—Cable in HDPE Flexible Conduit 311.16 Present Worth of Cable Installation Options 311.17 Separate Service Cables 321.18 Secondary Pedestal 321.19 Sample Cable Loss Analysis 351.20 Sample Secondary Cable Data 361.21 Savings from Deferred Transformer Energization 371.22 Savings from Deferred Transformer Installation 38

2.1 Dimensional Characteristics of Common Conductors(Standard Concentric-Lay) 53

2.2 Conductor Physical and Electrical Characteristics 542.3 Configurations of 4/0 AWG Aluminum Conductor 572.4 RUS Insulation Thickness 592.5 Insulation Shield Strippability Ratings 662.6 Concentric Neutral Configurations for Common Aluminum Cables 672.7 Comparison of Jacketing Material Test Data 712.8 Static Coefficient of Friction for Jacketing Materials in PVC Conduit 72

3.1 Multiplying Factors to Determine Asymmetrical Fault CurrentsWhere Symmetrical Fault Currents Are Known 83

3.2 Effective Cross-Sectional Area of Shield 913.3 Values of T1, Approximate Shield Operating Temperature, °C, at

Various Conductor Temperatures 923.4 Values of T2, Maximum Allowable Shield Transient Temperature, °C 923.5 Values of M for the Limiting Condition Where T2 = 200°C 923.6 Values of M for the Limiting Condition Where T2 = 350°C 923.7 Approximate Levels of I2t (Amperes2 x Seconds) That May Result in

Destructive Transformer Failure for Internal Faults 953.8 Approximate Levels of Fault Current Symmetrical (Amperes) That May

Result in Destructive Transformer Failure for Internal Faults 95

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4.1 Ampacities for Single-Phase Primary Underground Distribution Cable—XLPE, TR-XLPE, and EPR Insulated 123

4.2 Typical Ambient Soil Temperatures at a Depth of 3.5 Feet 1284.3 Ampacity for 15-kV Copper Conductor, Direct Buried, Single Circuit,

75% and 100% Load Factor 1304.4 Ampacity Table for 15-kV Aluminum Conductor, Direct Buried, Single

Circuit, 75% and 100% Load Factor 1314.5 Pros and Cons of Installing Cable Circuits in Conduit 1334.6. Ampacity Values—15-kV Cable, Trefoil Configuration,

Copper Conductor 1354.7 Ampacity Values—15-kV Cable, Trefoil Configuration,

Aluminum Conductor 1354.8 Abstract of ICEA Standards for Maximum Emergency-Load and

Short-Circuit-Load Temperatures for Various Insulations 1374.9 Correction Factors to Convert from 25°C Ambient Soil Temperature

to 20°C and 30°C 1394.10 Correction Factors for Various Ambient Air Temperatures 1394.11 Typical Ampacities for Various Sizes and Types of 600-Volt Secondary

UD Cable—Stranded Aluminum Conductors 1434.12 Average Temperatures for July and August Averaged for the Previous

10 Years 1464.13 Daily Peak Loads Per Unit of Nameplate Rating for Self-Cooled

Oil-Immersed Transformers to Give Minimum 20-Year Life Expectancy 1484.14 Application of Single-Phase Distribution Transformers to Serve

Residential Consumers—Sample Loading Guide 1504.15 Typical Watts-Per-Square-Foot Factors for Commercial Buildings 1534.16 Typical Electrical Load Power Factor Values 1534.17 Typical Electrical Load Demand Diversity Factor Values 1544.18 Estimated Electrical Demand (Summer) and Energy Consumption

(Sample Family Restaurant) 1554.19 Estimated Peak Duration 1564.20 Transformer Loading Capability Table 1564.21 Typical Three-Phase Pad-Mounted Transformer Capacities—

Short-Term Overload Capabilities (in kVA) 1564.22 Surface Temperatures Measured at Various Locations on the

Cases of Pad-Mounted Transformers. 1594.23 Surface Contact Time to Produce Burning 1604.24 NEMA Starting Code Letters 161

5.1 Surge Withstand Strengths of Polyethylene Insulating Jackets for15-kV, 25-kV, and 35-kV Class JCN Cable 176

5.2 2007 NESC Ground Rod Requirements for JCN Cable Installations 1845.3 Spacing of Test Probes for Testing Resistance of a Single Ground Rod 1945.4 Spacing of Test Probes for Testing Resistance of an Electrode System 1945.5 Soil Resistivities for Different Soil Types and Geological Formations 1975.6 Effect of Temperature on Soil Resistivity 198

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5.7 Ground Resistance in Varying Soil Resistivities 2045.8 Comparison of Protective Characteristics of Heavy-Duty Distribution

Class Silicon Carbide, MOV, and Riser Pole MOV Arresters 2095.9 Typical Electrical Ratings and Characteristics of Dead-Front

Surge Arresters 2135.10 Comparison of Standard Requirements for Surge Arrester Classifications 2145.11 Metal Oxide Surge Arrester Ratings in (kV) rms 2155.12 Protective Margin, 24.9-kV Underground Distribution System:

125-kV BIL Insulation, 18-kV Arresters at Riser Pole Only,10-kA Lightning Discharge, Surge Voltage Doubled by Reflection 219

5.13 Protective Margin, 12.47-kV Underground Distribution System:95-kV BIL Insulation, 9-kV Arresters at Riser Pole Only,10-kA Lightning Discharge, Surge Voltage Doubled by Reflection 220

5.14 Recommended Arrester Locations 2295.15 MOV Riser Pole Arrester: Arrester Rating, 10 kV; Equipment BIL,

95 kV; Aged BIL, 76 kV 2345.16 MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4):

Arrester Rating, 10 kV; Equipment BIL, 95 kV; Aged BIL, 76 kV 2345.17 MOV Riser Pole Arrester: Arrester Rating, 21 kV; Equipment BIL,

125 kV; Aged BIL, 100 kV 2355.18 MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4):

Arrester Rating, 21 kV; Equipment BIL, 125 kV; Aged BIL, 100 kV 2355.19 MOV Riser Pole Arrester Plus Dead-Front Cable-End Arrester (No. 4)

and Dead-Front Third Arrester (No. 3): Arrester Rating, 21 kV;Equipment BIL, 125 kV; Aged BIL, 100 kV 236

5.20 Ground Resistance Testers 237

6.1 Values for Equivalent Capacitances of an Overhead Line with4/0 ACSR Phase Conductors and a 1/0 ACSR Neutral Conductor 248

6.2 Representative Capacitance and Three-Phase Charging for XLPEInsulated Cables with 175 Mils Insulation 249

6.3 Representative Capacitance and Three-Phase Charging or XLPEInsulated Cables with 220 Mils Insulation 249



6.6 Phase-to-Ground Capacitance of Three-Phase Grounded-WyeCapacitor Banks 251

6.7 Maximum Allowed Cable Lengths in 12.47-kV Systems to LimitOpen-Phase Voltages to 1.25 PU 265



6.10 Transformer and Cable Data for the System of Figure 6.17 272

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7.1 Typical DC Potentials in Soil 2837.2 Suggested DC Potentials for Cathodic Protection 2867.3 Calculated Resistance and Conductance to Ground of Individual

Ground Rods as Related to Soil Resistivity 2887.4 Potentials to a Copper-Copper Sulfate Half Cell 2897.5 Sacrificial Anode Resistance, Output Current, and Estimated Life 2907.6 Conductance to Ground of BCNs with Effective Diameters as Indicated 291

8.1 Minimum Cover Requirements 3048.2 Requirements for Random-Lay Joint Trench 309

9.1 Classifications of Plastic Conduit 3149.2 PVC Duct Dimensions—Minimum Wall Thickness 3149.3 Comparison of Characteristics for Four-Inch Size PVC Duct 3149.4 PVC Duct—Impact Strength (Foot-Pounds) 3159.5 PVC Duct Collapse Pressure (PSI) 3189.6 Conduit Fill 3209.7 Conductor Shield Thickness 3209.8 Insulation Shield Thickness 3209.9 Concentric Neutral Thickness—Aluminum Cables 3209.10 Concentric Neutral Thickness—Copper Cables 3219.11 Secondary Cable Insulation Thickness 3219.12 220-Mil Primary Cable: Minimum Size of Conduit Necessary to

Accommodate Primary Underground Power Cable: 15-kV Cable—220-Mil Insulation Wall, Concentric Neutral Construction 322

9.13 260-Mil Primary Cable: Minimum Size of Conduit Necessary toAccommodate Primary Underground Power Cable: 25-kV Cable—260-Mil Insulation Wall, Concentric Neutral Construction 323

9.14 345-Mil Primary Cable: Minimum Size of Conduit Necessary toAccommodate Primary Underground Power Cable: 34.5-kV Cable—345-Mil Insulation Wall 324

9.15 Conduit Fill—Secondary Cable: Minimum Size of Conduit Necessaryto Accommodate 600-Volt Secondary Underground Power Cable 325

9.16 Recommended Dynamic Friction Coefficients for Straight Pulls andBends Using Soap/Water or Polymer Lubricants 333

9.17 Inside Bend Radius for 90° Schedule 40 Conduits 3359.18 Recommended Maximum Sidewall Bearing Pressures 3379.19 Cable Configuration for Various Jam Ratios 3389.20 Recommended Maximum Pulling Tension Stress for Pulling Eyes

on Copper and Aluminum Conductors 3399.21 Recommended Maximum Pulling Tension Limits for Basket-Type

Pulling Grips 339

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10.1 Electrical Rating of Elbows 35010.2 Relative Corrosion Resistance of Metal Combinations for

Outdoor Terminations 353

11.1 Dimensions for Primary Cables to ICEA Specification S-94-649-2000with Concentric Neutral (Concentric Stranding) 361

11.2 Dimensions for Primary Cables to ICEA Specification S-94-649-2000with Concentric Neutral (Compressed Stranding) 362

11.3 Cable Diameter Tolerances 36311.4 Adders for Extruded Insulation Shield (Mils) to Obtain Nominal

Diameter Over Insulation Shield of Cable 36311.5 DC Proof-Test Voltages (Conductor to Ground) for Primary Cables 36711.6 Insulation Thickness of Secondary Cables 36911.7 Manufacturers’ Voltage Withstand Tests on Completed Cable 37111.8 Manufacturers’ Voltage Tests on Cables Rated 0 to 600 Volts 371

A.1 Acceptable Outage Hours Per Year Per Consumer 374

B.1 Allowable Voltage Drop on a 120-Volt Base 377B.2 Resistance of Class B Concentric-Strand Aluminum Cable with

Thermosetting and Thermoplastic Insulation for SecondaryDistribution Voltages (to 1 kV) at Various Temperatures andTypical Conditions of Installation 380

B.3 Corrections for Multiconductor Cables 382B.4 Comparison of Conductor Diameter and Approximate Cable

Outside Diameter of Typical Single, Class B Concentric-StrandAluminum Cables 382

B.5 60 Hz Reactance of Conductors in the Same Conduit 384

C.1 Nominal Composite Insulation Layer Thickness (Ruggedized) 392C.2 Nominal Insulation Thickness (Non-Ruggedized) 392

E.1 Extruded Conductor Shield Thickness 400E.2 Nominal, Minimum, and Maximum Insulation Thickness 400E.3 Insulation Shield Thickness for Cables with Wire Neutral 401E.4 Extruded-to-Fill Jacket Thickness 402

xvi i i – Tables

tables

TABLE PAGE

G.1 Configuration No. 1—15-kV Copper 415G.2 Configuration No. 1—15-kV Aluminum 415G.3 Configuration No. 1—25-kV Copper 416G.4 Configuration No. 1—25-kV Aluminum 416G.5 Configuration No. 2—15-kV Copper 416G.6 Configuration No. 2—15-kV Aluminum 416G.7 Configuration No. 2—25-kV Copper 417G.8 Configuration No. 2—25-kV Aluminum 417G.9 Configuration No. 2, 3-Inch Type DB Conduit—15-kV Aluminum 417G.10 Configuration No. 2, 3.5-Inch Type DB Conduit—25-kV Aluminum 417G.11 Configuration No. 3—15-kV Copper 418G.12 Configuration No. 3—15-kV Aluminum 418G.13 Configuration No. 3—25-kV Copper 418G.14 Configuration No. 3—25-kV Aluminum 418G.15 Configuration No. 4—15-kV Copper 419G.16 Configuration No. 4—15-kV Aluminum 419G.17 Configuration No. 4—25-kV Copper 419G.18 Configuration No. 4—25-kV Aluminum 419G.19 Configuration No. 5—15-kV Copper 420G.20 Configuration No. 5—15-kV Aluminum 420G.21 Configuration No. 5—25-kV Copper 420G.22 Configuration No. 5—25-kV Aluminum 420G.23 Configuration No. 6—15-kV Copper 421G.24 Configuration No. 6—15-kV Aluminum 421G.25 Configuration No. 6—25-kV Copper 421G.26 Configuration No. 6—25-kV Aluminum 421G.27 Configuration No. 6, 6-Inch Type EB Conduit—15-kV Aluminum 422G.28 Configuration No. 6, 6-Inch Type EB Conduit—25-kV Aluminum 422G.29 Configuration No. 7—15-kV Copper 422G.30 Configuration No. 7—15-kV Aluminum 422G.31 Configuration No. 7—25-kV Copper 423G.32 Configuration No. 7—25-kV Aluminum 423

I.1 Cable Installation Equipment Manufacturers (Trenchers, Backhoes,Cable Plow, Guided Boring Tools, Piercing Tools, HydraulicPipe Pusher, Track-Mounted Cable Plows, Trench Compactors,Auger-Type Boring Tools) 427

I.2 Cable Installation Equipment Manufacturers (Primary Circuit Joints,Elbows, and Terminations; Secondary Circuit Joints and Terminations) 428

I.3 Manufacturers of Joint, Elbow, and Termination Accessories and Kits 429I.4 Partial Listing of Cable Testing Equipment Suppliers 429

Tables – xix

tables

TABLE PAGE

1.1 Cable Loss Calculations 351.2 Calculating Losses on Secondary Cables 361.3 Typical Costs Associated with Transformer Losses 37

3.1 Device Rated in Maximum Asymmetrical Current Capacity 833.2 Device Rated for Maximum Circuit X/R Ratio 843.3 Determine Minimum Shield Size for Known Through-Fault Current 93

4.1 Comparing the Ampacity of Trefoil and Flat-Spaced Configurations 1314.2 Single-Phase UD Cable Ampacities 1404.3 Emergency Overload Rating Cable in Protective Riser 1414.4 Three-Phase Substation Exit Ampacity 1414.5 Average Daily Temperature Selection for a Summer-Peaking Utility 1464.6 Selection of Maximum Permissible Transformer Per-Unit Loading 1494.7 Pad-Mounted Transformer Sizing for New UD Residential Consumers 1514.8 Sizing Commercial Transformers 1574.9 Dedicated Transformer Load 160

5.1 No Counterpoise Added (Switches S1, S2, and S3 Open) 1915.2 Attaching a 100-Foot Counterpoise to the Riser Pole Ground Rod and

the Other End to a Remote, Smaller Resistance (Switch S2 Closed;S1 and S3 Open) 191

5.3 Continuous or Full-Length Counterpoise (Switches S1 and S3 Closed;S2 Open) 191

5.4 A Single 8-Foot × 3/4-Inch Ground Rod Driven in Soil with aResistivity of 250 Ohm-M 201

5.5 Two 8-Foot × 3/4-Inch Ground Rods Placed 5 Feet Apart 2025.6 Two Rods Spaced 16 Feet Apart 2025.7 Group of Four Rods 2035.8 Increase in Rod Length 2045.9 Change in Soil Resistivity 2045.10 The Effect of a Two-Layer Soil with a Top-Layer Resistivity of

250 Ohm-M and a Bottom-Layer Soil Resistivity of 50 Ohm-M 2055.11 Counterpoise of #2 AWG Conductor Buried 30 Inches Deep for a

Distance of 100 Feet 2065.12 More Conductive Soil 2065.13 Counterpoise Burial Depth 2065.14 Protective Margin Calculation for Riser Pole Application—

Industry Standard 4 kA/µs Average Rise Time for LightningStrokes Assumed 217

5.15 MOV Riser Pole Arrester: Arrester Rating, 10 kV 2345.16 MOV Riser Pole Arrester and Dead-Front Cable-End Arrester

(No. 4): Arrester Rating, 10 kV 2345.17 MOV Riser Pole Arrester: Arrester Rating, 21 kV 235

xx – Examples

examples

EXAMPLE PAGE

5.18 MOV Riser Pole Arrester and Dead-Front Cable-End Arrester(No. 4): Arrester Rating, 21 kV 235

5.19 MOV Riser Pole Arrester Plus Dead-Front Cable-End Arrester (No. 4)and Dead-Front Third Arrester (No. 3): Arrester Rating, 21 kV 236

6.1 Maximum Lengths of Cable Circuit Possible 2646.2 Energizing Multiple-Transformer System with Single-Pole 272

7.1 Measuring Earth Resistivity 2847.2 Calculating the Neutral Conductance to Ground Per 1,000 Feet of Cable 2887.3 Determining Required Shift in Potential 2897.4 Calculating Required Anode Output Current 2897.5 Selecting Anode Types, Sizes, and Numbers 2917.6 Estimating Neutral Conductance to Ground of BCN Cable 2927.7 Determining Required Shift in Neutral Potential 2927.8 Determining Output Current and Anodes Required 293

11.1 Diameter Calculation 363

B.1 Transformer Voltage Drop Calculation 379B.2 Secondary Cable Resistance and Reactance 383B.3 Complete Secondary Voltage Drop Calculation 385B.4 Voltage Flicker Calculation 387

G.1 Ampacity Reduction for Direct-Buried Versus Conduit Encasementfor Flat-Spaced Installation 417

G.2 Increase in Ampacity for Duct Bank Installation When Type EBConduit is Used Versus Schedule 40 422

J.1 Cable Pulling Example 1: Maximum Straight-Pull Distance for Three25-kV Cables Installed in Five-Inch PVC Conduit 431

J.2 Cable Pulling Example 2: Feasibility of Pulling Three 25-kV Cablesinto a Six-Inch PVC Conduit 432

Examples – xxi

examples

EXAMPLE PAGE

Design of an Underground Distr ibut ion System – 1

Design of an UndergroundDistribution System1

In This Section:

Since their introduction, underground distribution(UD) systems have proved generally popular withelectric consumers. Although some of this popu-larity is due to aesthetics—eliminating pole linesand overhead conductors and “ugly” tree trim-ming—greater reliability is the greater attraction.Consumers facing outages due to wildlife, fallingtree limbs, and ice storms think underground sys-tems more desirable. Unfortunately, many of thepresent UD systems are less reliable and havemore operational problems than do comparableoverhead distribution systems. To reverse thistrend, cooperatives must undertake severalcomprehensive steps:

1. Specify high-quality materials and components,2. Stipulate every safety provision to ensure

reliability of the system,3. Design efficient systems that will have the

lowest reasonable cost for both installationand operation, and

4. Plan carefully to minimize problems duringconstruction and provide for future opera-tion and replacement of these systems.

This section gives the engineer guidelinesfor designing a high-quality UD system. Beforestarting a design, the engineer must have com-prehensive knowledge of the components of aUD system. Next, the engineer must under-stand how these components can be config-ured to form different types of UD systems andthe special design concerns of each. Duringthe design process, the engineer must considerthe following:

• UD system safety,• UD system reliability,• UD system operation and maintenance,• Future upgrades or replacement,• The economics of different systemconfigurations, and

• The economics of UD losses.

The final design task is layout of the UDsystem. On completing this task, the engineerwill have a final plan and staking sheets to giveto construction crews.

System Components

Types of UD Systems

Reliability of UD Systems

Design Considerations

Future Upgrades and Replacements

Economic Comparison of SystemConfigurations

UD Loss Economics

Steps for Layout of a UD System

Summary and Recommendations

2 – Sect ion 1

In the past, some UD systemswere total underground systemswith all components locatedbelow ground. Placing trans-formers, sectionalizing devices,and switches below ground re-quires buried vaults. Becausewater often accumulates inthese vaults, the equipmenthas to be suitable for operationunder water. Moisture also ac-celerates the corrosion of this equipment andleads to premature equipment failure.This type of system is very difficult to operate

and maintain. Maintenance and operation of theequipment usually require a person to enter theunderground enclosure. If the enclosure is fullof water, the water must be pumped out before

anyone enters. This require-ment increases the timeneeded to access the equip-ment and, thus, also increasesthe duration of any outage.Because of these problems,

a total underground system isimpractical and unreliable. Amore reliable system consistsof underground cables andpad-mounted equipment

(transformers, sectionalizing devices, andswitches). The pad-mounted equipment isplaced on the surface instead of below ground.As a result, the equipment is easier to operateand subject to fewer corrosion problems. Thistype of UD system, with its major system com-ponents, is shown in Figure 1.1.

1SystemComponents A typical UD system

consists of buried

cables and

pad-mounted

equipment.

Underground Cable,Primary Voltage

Underground Cable,Secondary Voltage

Dead-FrontSurge ArresterFlat Pad

Box Pad

Ground Line

Ground Electrode Ground Electrode Service Ground

Cable Splice

Cable Terminations

Underground Cable Riser

Pad-MountedSwitchgear/

Junction CabinetPad-MountedTransformer

Surge ArresterCable Termination

FIGURE 1.1: UD System Components.


UNDERGROUND CABLEThe most extensive component of a UD systemis the underground cable. The primary-voltage(15-, 25-, or 35-kV class) cable carries powerfrom a source to the primary bushing of a trans-former. The secondary-voltage (600-Volt class)cable carries power from the secondary bushingsof the transformer to the consumer. Section 2,Cable Selection, describes cable construction andgives guidelines for specifying high-quality cable.

PAD-MOUNTED EQUIPMENTThe main types of pad-mounted equipment aretransformers, protective devices, and switchingdevices. Pad-mounted transformers function thesame as those overhead. Pad-mounted switchgearusually functions as a combination of switchesand sectionalizing devices. For example, a singleenclosure can provide switching on the mainfeed and fusing on two taps off the main feed.Figure 1.2 shows the schematics for several typesof switchgear. Section 3, Underground SystemSectionalizing, reviews the different types ofpad-mounted switchgear. Because of the many

configurations possible, this component pro-vides the engineer with many options in thedesign of a UD system.

CABLE TERMINATIONS AND JOINTSCable terminations and joints are other impor-tant components of a UD system. The joints pro-vide a way to connect two underground cables.The terminations provide a way to connectunderground cables to transformer bushings,switches, fuses, and other devices. Section 10describes the different types of terminations andhow to use them on a UD system.

SURGE ARRESTERS ANDGROUNDING ELECTRODESSurge arresters are used to protect undergroundsystems from overvoltages induced by lightningand other transients. To operate effectively, ar-resters must be properly connected to the cablegrounding system. The grounding system musthave ground electrodes that are in optimumcontact with the soil. Examples of groundelectrodes are:

1

FIGURE 1.2: Schematics for Different Types of Switchgear. Adapted from S&C Electric Company, 2005.

kV Ampere, RMS Short-Circuit

Fuse Mini-Rupter

LoadMax Cont. Dropping

14.4 17.0 95 200 600 600 350

25 27 125 200 600 400 540

Nom. Max BILMVA 3-Phase

Sym. atRated Voltage

PME-4

COMPARTMENT - 2

COMPARTMENT - 1

COMPARTMENT - 2

COMPARTMENT - 1

COMPARTMENT - 3

COMPARTMENT - 2

COMPARTMENT - 4

COMPARTMENT - 1

COMPARTMENT - 3

COMPARTMENT - 2

COMPARTMENT - 4

COMPARTMENT - 1

COMPARTMENT - 3

COMPARTMENT - 2

COMPARTMENT - 4

COMPARTMENT - 1

COMPARTMENT - 3

COMPARTMENT - 2

COMPARTMENT - 4

COMPARTMENT - 1

COMPARTMENT - 3

COMPARTMENT - 2

COMPARTMENT - 4

COMPARTMENT - 1

PME-9 PME-10 PME-11 PME-12

PME-5 PMH-6

4 – Sect ion 1

• Driven ground rods,• Buried counterpoise wires,• Semiconducting jacketed cables, and• Metallic water or sewer systems.

Figure 1.1 shows driven ground rods as theground electrodes. Detailed information oncable grounding systems and surge protection iscontained in Section 5.

EQUIPMENT MOUNTINGSEquipment mountings provide a flat, rigid sur-face for supporting pad-mounted equipment. Itis very important to mount thebottom edge of pad-mountedequipment flush to the flat sur-face of the supporting pad.Doing so prevents personsfrom poking a wire or otherobject into the interior com-partment of pad-mountedequipment and meets therequirements of American National StandardsInstitute/Institute of Electrical and ElectronicsEngineers (ANSI/IEEE) C57.12.28 (Standard forPad-Mounted Equipment-Enclosure Integrity)and ANSI/IEEE37.74 (Standard Requirementsfor Subsurface, Vault and Pad-Mounted LoadInterrupter Switchgear and Fused Load-Inter-rupter Switchgear for Alternating Current Sys-tems Up to 38 kV). The former code hasbecome a standard for specifying tamper-resis-tant pad-mounted equipment enclosures. Thistamper-resistant design helps prevent vandalismto utility equipment and protect the public fromcontact with energized parts.The equipment must also attach securely to

the mounting surface to prevent it from beingmoved or tipped over by people, animals, lawnmowers, or vehicles. Secure attachment is partic-ularly important when polyethylene pads areused. The pad’s slick surface makes it easy foran unsecured piece of equipment to slide.Another important factor in a stable installa-

tion is proper soil compaction beneath the pad.Without proper compaction, the soil will settleand erode, leaving the pad with little support.When this happens, pads can tilt or warp (ifmade of polyethylene) and expose the interior

compartments of transformers, fuse cabinets,or switchgear. If the settling is severe, the padmay not support all the equipment weight. Ifsome of the equipment weight is transferred tothe attached cables, this settling can damagetransformer bushings, connectors, and switchterminals.

Types of Equipment MountingsThe most basic type of equipment mounting is aflat, or monolithic, pad. The flat pad provides auniform surface for mounting equipment and hasopenings for cable access into the equipment en-

closure as shown in Figure1.3. Because this pad is placeddirectly on the ground, thereis limited space for cable train-ing and cable terminations.However, this type of pad isusually adequate for single-phase pad-mounted transform-ers and small single-phase

sectionalizing devices.Some types of cable installations require more

space than is available with a flat pad. For ex-ample, large-diameter cables are stiffer and havea larger minimum bending radius than do small-diameter cables. Thus, the large-diameter cablesrequire more space for cable training. Anotherconsideration is cold weather. Low temperaturesmake cables stiffer and more difficult to installor operate. Providing additional cable spacehelps minimize these problems. Therefore, co-operatives in areas with extended periods ofcold weather may prefer using a ground sleeve(“basement”) or a box pad instead of a flat pad.A ground sleeve or box pad also provides theextra space needed for large-diameter cables.Typical installation of a ground sleeve is

shown in Figure 1.4. The ground sleeve is in-stalled below the ground surface, with theequipment mounting surface elevated two tothree inches above final grade. This type ofmounting provides additional space for cablesbelow grade, but is suitable for equipment withonly one entry compartment such as three-phasepad-mounted transformers and junction cabinets.Ground sleeves are generally limited in theirability to support heavier pieces of equipment.

1

The soil beneath

the pad must be

well compacted.


The third type of mountingis a box pad (see Figure 1.5).The box pad is placed in theground rather than on the sur-face, with typically three to sixinches exposed above grade.A perimeter lip supports thepad-mounted equipment. Theremaining space is open and

1

FIGURE 1.3: Flat Pad for Equipment Mounting.

FIGURE 1.4: Ground Sleeve. Source: NordicFiberglass Inc., Warren, Minn., 2002.

FIGURE 1.5: Box Pad for Equipment Mounting.

provides plenty of room to work with the ca-bles. This type of pad is ideal for supportingpad-mounted switchgear that has multiple cableentry compartments.

Pad MaterialsManufacturers offer a varied selection of padmaterials, including the following:

• Steel-reinforced concrete,• Fiberglass-reinforced concrete,• Fiberglass, and• Polyethylene.

Because these materials have very differentproperties, the engineer must carefully selectthe material type suitable for the intended ap-plication. The material and pad design musthave the strength required to support theequipment weight. This is of particular con-cern with box pads, because all the equipmentweight is supported by the outside pad walls,

and is especially important,for example, when box padsare used for transformers500-kilovolt amperes (kVA)and larger. Care must be ex-ercised in making sure thebox pad manufacturer clearlystates the strength rating ofthe box pad walls.

Pad material must

be suitable for the

intended application.

6 – Sect ion 1

Also of concern are polyethylene pads withwooden braces. A puncture through the poly-ethylene allows water to enter the pad and rotthe wooden braces. When the wooden bracesrot, part of the pad strength is lost, and war-page results.A second property to review is the performance

of the material outdoors where it is exposed tofrost and ultraviolet radiation. The pad materialsmust not break down or crack from ultravioletexposure or frigid conditions. Cracks or materialbreakdown lead to a loss of mechanical strength.

A final property to review is pad buoyancy.Some of the polyethylene pads tend to float andcan overturn pad-mounted equipment. There-fore, these pads would not be suitable for use inareas that are subject to flooding.In summary, pads must be of a design that

will have long-term durability under adverseconditions, meet system operating needs, andmaintain equipment security. All these factorsmust be balanced when selecting a pad designfor a particular UD system.

1

Types of UDSystems

SUBSTATION CIRCUIT EXITSUnderground cable is often used for substationcircuit exits from distribution substations. Under-ground circuit exits help reduce congestion onpoles just outside a substation, making the areaaround a substation more attractive and work-able. As an added benefit, underground substa-tion circuit exits are protected from ice loading,wildlife contacts, and vehicle damage, and, thus,may be more reliable than overhead exits.In most cases, each underground substation

circuit exit will terminate on a riser pole andfeed overhead circuit conductors. Therefore, thistype of UD system consists of underground pri-mary-voltage cable, cable terminations, surge ar-resters, and grounding electrodes. The conduit,cable terminations, surge arresters, groundingelectrodes, and disconnect switches are commonlyreferred to as a riser assembly. See Figure 1.6.When designing underground substation circuit

exits, the engineer must be particularly concernedwith reliability. If the underground cable fails, thecircuit outage interrupts power to many consumers.Placing the cable in a conduit system or concrete-encased duct bank helps protect it from mechan-ical damage. Section 9 contains information onduct bank installations. Another way to improvereliability is to install a sparecable or provide backup capa-bility from another source. Al-though spare cables or backupoptions do not change the riskof cable failure, they do reducethe power restoration time ifonly one cable is damaged.

A special concern for un-derground circuit exits is cableampacity. These cables carrylarge loads and may operateclose to their ampacity rating.Therefore, the engineer must

Design concerns for

substation circuit exits

are reliability, system

growth, and ampacity.

FIGURE 1.6: Underground SubstationCircuit Exit.

Disconnect Switches

SurgeArrester

CableTermination

Neutral

Riser Vent

Undergroung CircuitExit Cable

GroundElectrode


carefully determine the cable operating condi-tions, system growth, and the resulting ampacity.

MAIN FEEDERSUnderground cable can serve as a distributionmain feeder. A main feeder is that portion of adistribution circuit between the substation andthe first in-line overcurrent protective device.The protective device in the substation clears afault on a main feeder. Therefore, a main feederfault causes an outage to the entire circuit. Be-cause most faults on an underground mainfeeder are cable failures and are permanent,power to the circuit may remain off until thecable is repaired. The utility engineer must con-sider this characteristic when designing a mainfeeder, particularly when deciding between a ra-dial or open-loop feeder.The engineer must also determine the maxi-

mum load to be carried by the main feeder inorder to select a cable with adequate ampacity

and choose the 200-ampere or 600-ampere classof cable terminations. Section 4 provides de-tailed information on cable ampacity, and Sec-tion 10 provides information on the types ofcable terminations.

Radial Main FeederThe radial main feeder has one source and de-livers power to a load area along a single path.This feeder can also serve several load areas byusing a junction box or sectionalizing switchwith fused taps. This type of arrangement isshown in Figure 1.7 and may have the followingcomponents:

• Underground primary-voltage cable,• Cable terminations,• Pad-mounted junction box or sectional-izing switch,

• Surge arresters, and• Grounding electrodes.

1

FIGURE 1.7: Radial Main Feeder.

Junction Box orSectionalizing Switch


Substation

Junction Box orSwitching Cabinet

Primary Voltage Cable

To Load Area

ToLoadArea

ToLoadArea

8 – Sect ion 1

The junction box or sectionalizing switchprovides sectionalizing of the load areas andlimited sectionalizing of the main feeder. For ex-ample, consider a fault in the second line sec-tion as shown in Figure 1.8. This fault trips theprotective device at the substation and interruptspower to all consumers on the faulted circuit.The cooperative can restore power to the firstload area by placing the faulted cable(s) in aparking stand, or by opening the load-sideswitch on the first sectionalizing switch to isolatethe faulted cable. Figure 1.8 shows this option.Because the radial feeder has no alternativesource or path, the cooperative cannot restorepower to the other consumers until crews repairthe cable fault.It is possible to improve the reliability of a

radial system by installing the cable in a con-crete-encased duct bank or in a conduit system,or by installing a spare cable or conduit in thetrench. A concrete-encased duct bank provides

substantial mechanical protection from dig-insand should be considered in areas congestedwith other underground utilities. A conduit sys-tem provides limited mechanical protection.However, it does decrease outage time by allow-ing the cooperative to replace a section offaulted cable without disturbing the earth sur-face. This saves substantial time, particularlywhen the main feeder is located beneath a road-way. The spare cable or conduit provides nomechanical protection but does decreaserestoration time if only one cable is faulted. Be-cause the costs of these installation methodsvary significantly, each cooperative must weighthe advantages of these more expensive installa-tions against their costs.Under any circumstance, the simple radial

does have limited operational flexibility andshould not be used to serve a large number ofconsumers. Information on comparative systemreliability may be found in Appendix A.

1

FIGURE 1.8: Radial Main Feeder with Faulted Cable Section.


Power Off

Substation

OpenLoad-Side Switch

Fault

Power OffPower On

Open

Power On


Open-Loop FeederIn dense load areas, an underground main feedermay tie together two substations. A main feedermay also tie two circuits from the same substation.This type of arrangement would operate as anopen-loop system. The components of this systemare the same as those of a radial system. However,the open-loop feeder has two sources, unlike theradial feeder that has only one source. Each sourceprovides power along a single path to the desig-nated open point in a junction box or a section-alizing switch. In a junction box, the open pointresults from placing one set of cables in a parking

stand. In a sectionalizing switch, leaving one ofthe switches open creates an open point.The open-loop feeder (see Figure 1.9) provides

much higher system availability than does theradial system. With an open-loop system, utilitycrews can isolate a faulted cable section and re-store power to all consumers. A cable fault inthe second line section interrupts power to allconsumers on that circuit. After isolating thefaulted cable section, as shown in Figure 1.10,crews can feed the first section from SubstationNo. 1 and remaining line sections from SubstationNo. 2. Because crews can restore power to all

1

FIGURE 1.9: Open-Loop Feeder.

Substation No. 2

N.O.

Sectionalizing Switch

N.O. = Normally Open Point

Looped-PrimaryCircuit

Substation No. 1

Three-Phase,Pad-MountedTransformer

FIGURE 1.10: Open-Loop Feeder with Faulted Cable Section.

Substation No. 2

N.O.

N.O.

Fault

Sectionalizing Switch

N.O. = Normally Open Point

Looped-PrimaryCircuit

Substation No. 1

Three-Phase,Pad-MountedTransformer

10 – Sect ion 1

load areas before repairing the cable fault, theoutage time is much shorter than with a radialfeeder. As a result, it is not critical to install thecable in a concrete-encased duct bank or conduit.However, as already noted, in areas congestedwith underground utilities, the concrete-encasedduct bank will help protect cables from dig-ins.Again, it is important to judge the benefits of in-stalling duct bank or conduit against the addi-tional cost. An open-loop feeder also requiresthat the designer consider the ampacity of thefeeder cables while serving all possible loopsegments, which may dictate the use of a largercable size than otherwise needed.Open-loop feeders provide much more oper-

ating flexibility than do simple radial feeders.System reliability considerations generally dictateopen-loop feeders as the preferred design.

SUB-FEEDERSThe more common underground feeder is the sub-feeder, also called a load area feeder. This typeof feeder has at least one stage of sectionalizingbetween it and the protective device at the sub-station. As a result, a fault on a sub-feeder doesnot interrupt power to the en-tire circuit and, thus, affectsfewer consumers than does asimilar fault on a main feeder.The two types of feeders

also have different functions.The basic function of a mainfeeder is to deliver power toload area feeders. The mainfunction of a sub-feeder is to

deliver power to consumers. Therefore, sectionsof cable on a sub-feeder often terminate in pad-mounted transformers. The sub-feeder can haveseveral configurations ranging from a simple ra-dial feeder to a complex multiloop feeder.

Radial FeederThe simplest type of load area feeder is a radialfeeder. The radial feeder is usually the mostpractical way to serve a single consumer. How-ever, a single consumer with critical loads, suchas a hospital or police station, often requires amore reliable system. Methods for improving re-liability include the following:

• Changing to an open-loop configuration,• Adding a spare cable or conduit to thetrench, and

• Placing the cable in a conduit or duct bank.

The radial feeder can be extended to servemultiple consumers as shown in Figure 1.11.However, a cable fault interrupts power to allconsumers beyond the fault location. For exam-ple, a fault between transformers T1 and T2 re-

sults in a power outage totransformers T2 through T5.The power remains off untilthe cable is repaired. As thenumber of consumers increases,it becomes more practical toconsider an open-loop system.The subsection EconomicComparison of System Con-figurations, which comes later

1

A cable fault on a

sub-feeder affects

fewer consumers than

does a similar fault

on a main feeder.

FIGURE 1.11: Radial Feeder.

T1 T2 T3 T4 T5

Fault

Power On Power Off

Single-Phase, Pad-Mounted Transformers

Riser Pole


in this section, provides information on theeconomics of radial versus open-loop systems.

Open-Loop FeederAs mentioned earlier, the open-loop feederhas two sources and, therefore, provides bettersystem availability. Large subdivisions or com-mercial shopping areas are ideal applications ofopen-loop systems. Figure 1.12 shows an open-loop feeder in a shopping center. Utility crewscan isolate any section of faulted cable andrestore power to all transformers. This featuremakes the open-loop feeder a preferred design

for UD systems serving multiple or criticalconsumers. An open-loop feeder also requiresthat the designer consider the ampacity of theprimary cables and devices while serving allpossible loop segments, which may dictate theuse of a larger cable size than otherwise needed.

Multiple-Loop FeederIn heavy load areas, multiple-loop feeders arenecessary to improve sectionalizing and to allowthe coordination of overcurrent protective devices.A typical multiple-loop system is shown in Fig-ure 1.13. This type of system usually has a sub-

1

FIGURE 1.12: Open-Loop Feeder in Shopping Center.

Three-Phase Feeder

Normally Open Point

Three-Phase, Pad-Mounted Transformers

Riser Pole Riser Pole

FIGURE 1.13: Multiple-Loop System.

Riser Pole Riser Pole

SectionalizingSwitch

SectionalizingSwitch

N.O.

N.O.

N.O.

N.O.

Legend

N.O. Normally Open Point

Single-Phase, Pad-MountedTransformer

N.O. Three-Phase, Pad-MountedTransformer

12 – Sect ion 1

feeder that serves as an open-loop system be-tween two sources. The sectionalizing switcheson the sub-feeder have fused taps that serveother open-loop feeders. This arrangementprovides excellent system availability. It alsospeeds up fault location because the large loadarea has been sectionalized into small loadgroups. A multiple-loop feeder also requires thatthe designer consider the ampacity of the feedercables and devices while serving all possibleloop segments, which may dictate the use of alarger cable size than otherwise needed.

TRANSFORMER AND SECONDARY SYSTEMSPad-mounted transformers and undergroundsecondary-voltage cable constitute the final seg-ment of a UD system. To properly design thispart of the system, the engineer must first selectthe appropriate equipment rating and cableampacity. Section 4 provides information formaking these selections.Second, the engineer must consider reliability.

Most secondary cable faults are the result of me-chanical damage to the cable. Utilities can mini-mize mechanical damage by following the prop-er installation techniques described in Section 9and by specifying cable with an abrasion-resistant

1

Ground Electrode

Cable Riser

Pole

Lighting Package

UndergroundSecondary-VoltageCable

FIGURE 1.14: Area Lighting System.

or self-healing insulating jacket (see Section 2).Cable dig-ins by other utilities or consumers alsodamage cable. To minimize dig-ins by con-sumers, cable should be installed two to threefeet off the property line. Doing so helps pre-vent cable damage if the consumer installs afence on the property line. Another method forminimizing dig-in damage is to use conduit. Theconduit offers some mechanical protection, par-ticularly from hand digging. As noted, the coop-erative may particularly want to use conduit inareas congested with other utilities.A third design concern with secondary systems

is voltage drop and voltage flicker. The engineermust design a system that provides the consumerwith acceptable voltage levels throughout theday and during motor starting. Appendix B liststhe acceptable voltage levels and gives methodsfor calculating voltage drop and flicker.

STREET AND AREA LIGHTINGPublic safety and consumer convenience requirestreet and area lighting in the area served by alarge percentage of underground projects. Mostcooperatives furnish this service, so the engineermust make accommodations in underground sys-tems to include it. The engineer needs to devel-op a plan at the start of the project for eventual(if not actual) street and area lighting. Conduitsand pedestals can then be installed at strategiclocations that will minimize future trenching inlawns or around consumer facilities.This type of UD system is shown in Figure 1.14.

It uses a combination of overhead components(poles and a lighting package) and undergroundcomponents (underground secondary-voltagecable, surge arresters, and grounding electrodes).Street and area lights are generally self-con-

tained units with an integral photoelectric cell forcontrol. These standard light packages usuallyoperate from 120-Volts single phase or 120/240-Volts single phase. The cooperative may wantto consider using the same lighting package thatit uses in overhead areas. Doing so will avoidunnecessary duplication of stock and minimizeconfusion during installation and maintenance.If the lighting package requires a 120-Volt,

two-wire power supply, service may be pro-vided through a two-wire duplex underground


cable. If the cooperative has alarge amount of undergroundstreet lighting, purchasing atwisted duplex cable with aruggedized insulation systemwill be most economical. Thiscable will essentially complywith the secondary cable spec-ification presented in Appen-dix C. When this duplex isused, the conductor may beeither copper or aluminum.When aluminum is used, the size should not besmaller than No. 6 American Wire Gauge (AWG).Satisfactory performance may be achieved withcopper conductors as small as No. 10 AWG. Inareas where deep frost lines are routine, largeraluminum conductors, possibly No. 2 AWG,might be considered as a minimum gauge.In cases of infrequent use or where ruggedi-

zed duplex cable is not readily available,Type UF (underground feeder) commercialcable may be substituted. This cable should bepurchased only with copper conductors No. 10AWG or larger. The Type UF cable must berated as sunlight-resistant. Otherwise, the cablemay deteriorate where it is exposed to sunlightbetween the pole riser conduit and the bottomof the lighting support bracket.Lighting packages may be installed on wood

poles at a height appropriate for the size of thelamp and the area to be lighted. On woodpoles, polyvinyl chloride (PVC) conduit shouldbe used to protect the cable riser. Schedule 40PVC is recommended as a minimum. U-guardsare not recommended because irregularities inwood poles may allow the smaller cable usedfor lighting service to protrude or be pinchedbetween the U-guard and the pole surface. Eachwood pole installation must be equipped with apole-grounding conductor (No. 6 AWG copper)that is attached to a driven ground rod. This isparticularly important because street and arealights are often among the highest objects in asubdivision served by an underground system.In cases of lightning strikes, the lightning musthave a relatively low impedance path into theearth. If pole grounding conductors are not in-stalled, a much larger portion of the lightning

current will travel along thelighting conductors and bepropagated into the secondaryof the transformer and into allconnected services. In areaswith intense lightning activity,the cooperative should considerinstalling secondary lightningarresters on each transformerthat serves a lighting installation.Where aesthetics are of prime

importance, cooperatives maychoose to install metal lighting poles. In suchcases, the height of the fixture mounting shouldnot be compromised; it should be installed inaccordance with standard practices for the partic-ular type of light and the size of the area to belighted. With metal poles, the pole interior maygenerally be used as a raceway to conceal theconductor along its entire length. In these cases,sunlight resistance will not be required on TypeUF cables if the cables are shielded from sun-light along their entire length. Metal poles willstill require adequate grounding to avoid prob-lems with lightning surges. Metallic poles shouldalso be directly connected to this same ground-ing system, which is also positively connected tothe neutral of the secondary supply conductors.If the poles are direct buried, they generallyhave an insulating coating for corrosion protec-tion. If direct-buried poles are installed or if thepoles are installed on poured concrete founda-tions, a ground rod is also recommended. Ifpoles are installed on a metal screw anchorbase, the ground rod may be eliminated.The main limitation on the layout of street

lighting conductors is voltage drop. As mostcontemporary lighting systems are either mer-cury vapor, metal halide, or high-pressuresodium systems, the most critical case is duringstarting of the most distant light. This is the timeof highest current draw and lowest power factor.The magnitude and power factor of the startingcurrent depend on the type of ballast, as doesthe acceptable voltage range for satisfactory op-eration. Table 1.1 gives examples of typical lightcharacteristics. It is obvious that the regulatorballasts offer a substantial advantage in allowinglong runs of small secondary voltage conductors

1Metallic lighting poles

must be grounded

and bonded to the

system neutral for

lightning protection

and for public safety.

14 – Sect ion 1

without unstable lamp operation. Moreover, alltypes of high-pressure sodium and metal halidelamps are more sensitive than are mercury vaporlamps to voltage dips. Therefore, all lighting cir-cuits should be designed for a voltage drop of

no more than 10 percent when the largest proba-ble lamp is started. Consideration should also begiven to selecting 240-volt ballasts as opposed to120-volt units, because they draw less currentand generally create decreased operating losses.

1Allowable Operating StartingVoltage Current Current Allowable

Size and Type Lumens Fluctuation (amperes) (amperes) Power Factor Voltage Dip

175-watt mercury vapor, normal power 7,950 240V±5% 1.6 2.6 55% 20%factor reactor ballast

400-watt mercury vapor, normal power 21,000 240V±5% 3.4 5.1 54% 20%factor reactor ballast

400-watt mercury vapor, regulator ballast 21,000 240V±13% 2.1 0.9 90% 50%

100-watt high-pressure sodium, normal 9,500 240V±5% 1.6 1.9 34% 10%power factor reactor

250-watt high-pressure sodium, normal 27,500 240V±5% 2.8 3.6 42% 10%power factor reactor

100-watt high-pressure sodium, high 9,500 240V±5% 0.6 0.9 90% 10%power factor reactor



250-watt metal halide floodlight, normal 20,500 240V±10% 1.3 1.0 90% 10%power factor reactor ballast

400-watt metal halide floodlight, normal 36,000 240V±10% 2.0 1.7 90% 10%power factor reactor ballast

TABLE 1.1: Lamp and Ballast Characteristics—240 Volts. Source: General Electric Lighting Systems Product Catalog 1985.

Reliability ofUD Systems

One of the most important advantages of a well-designed UD system is greater reliability for con-sumers compared to an overhead system. UDlines and equipment are located where they arenot vulnerable to most of the common hazardsthat cause outages on overhead facilities, suchas trees, weather, some animals, and vehicles.However, material or design defects in a UD sys-tem may reverse the reliability advantage of un-derground distribution. In fact, many early UDsystems installed by cooperatives and other utili-ties turned out to be less reliable than comparable

overhead systems. These experiences havemade it clear that reliability engineering is anecessary part of UD system design.

MEASUREMENT OF RELIABILITYReliability is usually measured in two ways. Thefirst is the frequency of interruptions occurringat a particular point on a system, referred to asthe interruption rate or outage rate. Outage ratesare measured in outages per year. The secondmeasure is the average duration of an interrup-tion, also referred to as the restoration time.


Outage duration is usually measured in hours. Acombination of these two measurements yieldsthe percentage of availability for a particular lo-cation on a distribution system. A simple indexof reliability used by many utilities is hours ofoutage per year, per consumer.For this discussion, outages are considered to

be sustained interruptions. Reliability calculationsof this type usually do not consider momentaryinterruptions that are successfully cleared by au-tomatic circuit reclosing operations. This analysisconsiders only those outages that require man-ual intervention to restore service. Furthermore,almost all faults attributable to underground sys-tem components are permanent.System reliability undeniably affects many as-

pects of a cooperative’s service. Although theorder of importance may vary with individualsituations, the results of distribution system out-ages include the following:

• Consumer dissatisfaction;• Consumer financial losses resulting frominterrupted production, equipment damage,or other causes;

• Impairment of other cooperative facilities;• Costs to the cooperative of service restora-tion; and

• Lost cooperative revenue.

All these factors have a serious impact on satis-factory cooperative system operation. Engineers,therefore, must be aware of the basic principlesof reliability assessment so they can achievesatisfactory but economical UD system designs.Appendix A provides a method for calculatingUD system reliability.Comprehensive reliability analysis also con-

siders the number of consumers or kVA of loadeach outage affects. Thus, facilities serving manyconsumers (or kVA) may need to be designedfor higher reliability than should facilities servingfew consumers (or kVA). The analysis presentedin this manual, however, does not consider thisparameter because most cooperative UD sys-tems are fairly uniform in design and consumerconcentration. There is generally no need to dis-criminate in design quality between some partsof the system and others.

CABLE FAILURE RATESIn the mid-1980s, the failure rates for common-ly used UD primary cables were unacceptable.The failure rates for cross-linked polyethylene(XLPE) and high-molecular-weight polyethylene(HMWPE) cables were approaching 0.02 and0.08 per mile per year, respectively. Further-more, studies revealed that these failure rateswere continuing to worsen as the cables aged.The most common causes of failure were elec-trochemical treeing of the insulation layer andcorrosion of the exposed neutral conductors.In December 1987, the Rural Electrification

Administration (REA), currently called Rural Util-ity Services (RUS), responded to the cable failureproblem by issuing a revision of Bulletin 50-70(U-1), REA Specification for 15-kV and 25-kVPrimary Underground Power Cable. The mainspecification changes were the following:

• Removing all HMWPE cable from approval,• Increasing minimum insulation thickness to220 mils for 15-kV cable and to 345 mils for25-kV cable, and

• Requiring cable to be jacketed.

At that time, RUS did not disapprove the useof XLPE cable. Nevertheless, concerns aboutXLPE were raised in studies, leading to the bul-letin’s revision.As a consequence of these experiences in the

1980s, cooperatives should procure new cablewith the requirement that the revised RUS specifi-cations be met. Any XLPE cable acquired shouldalso be tree retardant (TR-XLPE). As a result ofrecent vastly improved quality control in cablemanufacturing processes, both TR-XLPE- andethylene propylene rubber- (EPR) insulated ca-bles provide improved reliability. Industry testsare continuing to develop information on theexpected failure rates for different insulation sys-tems. RUS is currently preparing an even furtherrefined U-1 specification to reflect these continu-ing cable insulation improvements. Section 2discusses cable selection in detail.

LOOP-FEED DESIGNThe time spent to locate an underground cablefault, excavate to the point of its failure, and

1

16 – Sect ion 1

install a UD cable repair joint is typically muchlonger than that required to perform a compara-ble repair on an overhead line. Therefore, if theoverhead type of radial distribution system con-figuration were used for UD, the restoration timefor most UD outages would be much longerthan is typical on overhead systems.This difficulty is overcome by using loop-feed

design for UD systems. Under loop-feed design,each cable run serving several pad-mountedtransformers is connected with a power supplypoint on both ends (see Figure 1.15). Thisformed loop is opened at some point to allowuse of radial overcurrent protection methods andto prevent unwanted power transfers throughthe cable. If the cable fails, a repair crew candisconnect both ends of the failed cable sectionand close the circuit at the normal open point(see Figure 1.16). These actions promptly restoreservice to all consumers on the cable run. Thedamaged cable can then be repaired or replacedlater without causing additional outage time.It must be noted that it is vitally important for

loop-feed UD systems to be fed from twosources of the same feeder circuit out of a sub-station, with no switching or sectionalizing de-vices in between. Having the two sources fedfrom different feeder circuits could cause unex-pected high-power flow through the UD systemif the sources were tied together during switch-ing operations on the UD loop. These high cur-rent levels could result in exceeding cableand/or termination current-carrying ratings, orcould create outages on source fusing devices.Furthermore, on single-phase UD looped sys-tems, it is vitally important that both sources beconnected to the same phase for safe operation.

UD SYSTEM RELIABILITY STUDYWell-designed UD systems can provide improvedreliability relative to overhead systems. However,to achieve high reliability, the cooperative needsto apply the specialized engineering knowledgegained from many years of experience with under-ground power distribution. This knowledge coversthe field performance records of different types ofcables, the proper application of surge arresters,appropriate sectionalizing, and loop-feed de-signs, all of which are treated by this manual.

1

FIGURE 1.15: Loop-Feed Design of UD System Under Normal Conditions.

Riser PoleRiser Pole

Transformer T4

Parking StandSurgeArresters

To Ground Rod

CopperGroundConductor

To T3

X3

X1

X2

N.O.

T6

T5

T4

T1

T2

T3

Legend



To T5

Riser Pole

Damaged Cable Section

Riser Pole

Transformer T5Parking Stand

SurgeArresters

ToGroundRod

CopperGroundConductor

To T4

X3X1

X2

Transformer T6

Front View Showing Isolated, Damaged Cable Section

Parking StandSurgeArresters

ToGroundRod To

RiserPlate

X3X1

X2

T6

T5

T4

T1

T2

T3

Legend


Cable Fault

FIGURE 1.16: Loop-Feed Design of UD System with DamagedCable Section.


The cooperative’s involvement with a UD systemdoes not end after installation; the cooperativemust operate and maintain the system through-out its life. Because many components of a UDsystem are difficult to access, operation and main-tenance of the system can also be difficult. Forexample, it is difficult to access a pad-mountedtransformer that is surrounded by shrubbery orlocated too close to fences or buildings. Like-wise, it is difficult to repair a faulted cable that isburied beneath landscaped areas or utility build-ings. The engineer needs to be aware of theseproblems when considering whether to placefacilities along the front or rear property lineand also must consider the effect of joint-usetrench on operation and maintenance activities.

FRONT VERSUS REAR PROPERTYLINE PLACEMENTOne of the fundamental choices in UD systemdesign is whether to locate facilities along thefront property line or along the rear property line.Usually, this is a joint decision between the utilityand the consumer or developer. Consumers ordevelopers will have some authority because theymust normally give the utility an easement thatallows the installation of underground facilities.Often the consumers or developers believe

that pad-mounted equipment detracts from the

1DesignConsiderationsfor SystemOperation andMaintenance

Location Advantages Disadvantages

Placement along 1. More accessible for 1. More unsightly to consumerfront property line operation and maintenance

2. Greater potential for dig-ins2. Usually more accessiblefor installation 3. Potential for damage from

vehicles3. Often reduces outage time

4. Reduces cable replacementcosts

Placement along 1. Consumers preference for 1. Often requires more tree/rear property line equipment in backyard brush clearing

2. Possible more economical 2. Difficult to access forinstallation if lots share rear operation and maintenanceproperty lines

3. Usually higher cablereplacement costs

TABLE 1.2: Front Versus Rear Property Line Placement.

appearance of the property so they prefer theutility to locate facilities along the rear propertyline instead of in front of their houses. However,equipment along the rear property line is usuallydifficult to access and thus difficult to operateand maintain, particularly when there is noservice alley or backyards are fenced and haveno access gate large enough to accommodatea trencher or backhoe.In addition, the rear property line is not usual-

ly cleared of trees and may not be to final gradewhen cable is installed. As a result, preparingthe rear of the lot for cable installation can bemore costly and time-consuming than preparingthe front property line. The installation cost alsodepends on the subdivision layout and the loca-tion of other underground utilities. An economiccomparison of front versus rear property lineinstallation is covered later in this section underEconomic Comparison of System Configurations.A final consideration is the power restoration

time following an outage. When facilities arelocated on the front property line, it is muchfaster for utility crews to check for tripped faultindicators and to perform cable switching toisolate the faulted cable section. It is importantthat the utility engineer inform the consumer ofthis advantage of front-line placement.Table 1.2 summarizes the advantages and dis-

advantages of front and rear property line place-ment. The engineer can be guided by this tablein selecting the cable route. In most cases, place-ment along the front property line is more ad-vantageous. However, subdivision layout, thelocation of other utilities, or consumer relationsmay require placement along the rear propertyline. In these cases, installing the cable in con-duit or installing a spare conduit allows the utili-ty better access when cables have to be repairedor replaced.

JOINT-USE TRENCHIn some areas, the space allocated for under-ground utilities is very limited. In these areas,the utilities may agree to place facilities in acommon trench. Within this common (joint-use)trench, the different utilities usually maintain aminimum separation of 12 inches. The 2007 Na-tional Electrical Safety Code (NESC), Section 354,

18 – Sect ion 1

does allow the random separation (less than 12inches) of some utilities. Section 8 of this guide,Direct-Buried System Design, contains informa-tion on the NESC requirements and installationguidelines for joint-use trench.

Operational PrecautionsBefore agreeing to share a common trench, thecooperative should consider the potential foroperational problems. Each utility will have tomaintain its own facilities, which may requirecrossing other utilities to reach its facilities. Tominimize the risk of damaging other facilitiesduring excavation, operation crews need adrawing that shows a trench cross section andthe location of all facilities within the trench. Itis also helpful to show the presence of joint-usetrench on the operating map for the area.A joint-use trench with ran-

dom lay of electric, telephone,and cable television (CATV)cables creates additional oper-ating problems. This type oftrench requires telephone andCATV personnel to work nextto power cables. Jacketedpower cables resemble tele-phone cables. The cables mustbe well marked to preventmistaken identity. The NESC requires all direct-buried, jacketed, primary-voltage cable to have aspecific marking on its jacket. This marking isshown as Figure 350-1 in the 2007 NESC. TheNESC also has special requirements for bondingand grounding of electric, telephone, and CATVsystems using random separation in Section354D. Grounding and bonding are discussedfurther in Section 8.

Typical Contractual ArrangementsJoint-occupancy trenches require tremendouscoordination and cooperation from each utilityinvolved. To help structure these efforts andprovide proper agreements on liability, the coop-erative must prepare a contract for joint trenchuse. This contract would be similar to the con-tract for joint pole use.First, the contract should address construc-

tion concerns. It must state the required trench

dimensions and arrangement of all utility lines.The utility that opens the trench must abide bythese dimensions. Second, the contract shoulddefine who is responsible for installing the facili-ties. If each utility installs its own facilities, thenthe contract needs to state the required notifica-tion period before opening and backfilling atrench. If the other utilities receive proper notifi-cation but fail to send crews, the contract shouldstipulate any consequences, such as those below:

• Will the trench be closed or coveredtemporarily?

• Will the delinquent utility be charged?• Will a closed trench be reopened?

Third, the contract should state who is re-sponsible for acquiring easements and any per-

mits. The utility that opens thetrench should require copiesof the easements and permitsbefore starting construction.Also before construction, anyexisting underground facilitiesmust be located. The contractmust identify who is responsi-ble for requesting the locationof these utilities. Special back-fill and compaction needs

must be addressed. If select backfill is required,the contract should identify the party responsi-ble for acquiring the backfill material and decidehow the additional cost will be shared amongthe utilities.Fourth, the contract should address shared

costs. These costs include the following:

• Cost to open and close the trench,• Cost of the service if one utility installsall facilities,

• Penalties for reopening a trench,• Penalties for temporarily covering orbarricading an open trench, and

• Cost adders for select backfill.

Fifth, the contract should state that it is trans-ferable to a new owner. This transferability isparticularly important for joint-use contracts withCATV utilities.

1

Joint-use trench with

random separation

often creates

operating problems.


The cooperative engineer can improve the de-sign of a UD system by anticipating and provid-ing for future system upgrades. Changes to asystem in established yards, parking lots, orroadways are very expensive. If trenching meth-ods are used, the utility mustalso restore the soil surface.Such restoration could includereseeding grass, repaving, orpouring new concrete side-walks or driveways. Trenchingin established yards also tendsto create conflicts with prop-erty owners.The engineer can help avoid these problems

by planning for future conversions to three-phasecircuits and higher voltage levels. The engineercan also plan for future cable replacements byconsidering the use of conduit systems.

FUTURE VOLTAGE CONVERSIONSMany utilities are converting to higher distribu-tion system voltages to decrease line losses, im-prove circuit voltage profile, and increasesystem capacity. These conversions are typicallyscheduled to occur over an extended time. Theengineer will, therefore, need to refer to thelong-range work plan to locate those areas des-ignated for future voltage increases. For UD sys-tems in these areas, the engineer needs to adaptthe design to minimize material and equipmentchangeout at the time of voltage conversion.A simple design change involves installing

cable and cable terminations that are rated forthe higher voltage level. These two componentswill operate properly at the lower voltage andwill not have to be changed when the voltagelevel is increased. This simple design changeeliminates the need to replace all the under-ground primary voltage cable—a very expensiveand time-consuming task. An economic evalua-tion under the subsection Economic Comparisonof System Configurations (next page) shows thatthe cooperative will save money by initially in-stalling the higher voltage cable.Voltage conversion also requires an increase

in the insulation level of pad-mounted trans-formers and sectionalizing devices. To avoid fu-ture changeouts, the cooperative can initially

install dual-voltage transformers and sectionaliz-ing devices rated for the higher voltage level.The economics of these changes depend on thesubdivision layout and the number of years be-fore the voltage conversion. Before making

these design changes, the en-gineer needs to do an eco-nomic study similar to the onedescribed in Future VoltageConversions under the Eco-nomic Comparison of SystemConfigurations subsection be-ginning on the next page.

THREE-PHASE VERSUSSINGLE-PHASE INSTALLATIONMost large subdivisions are developed in stagesover time. For these types of subdivisions, theengineer should determine if a three-phasefeeder is required. A three-phase feeder is oftenhelpful for balancing a large amount of single-phase load and for providing better sectionaliz-ing. The future subdivision plans may show aclubhouse or sewer lift station. These types ofloads are often three-phase and, thus, require athree-phase primary circuit.If the engineer thinks the subdivision will

eventually require three-phase power, he shouldconsider installing a three-phase feeder insteadof a single-phase feeder. It is much easier to in-stall three cables initially than to install one ini-tially and two later. The subsection immediatelyfollowing, titled Economic Comparison of Sys-tem Configurations, presents an economic com-parison of an initial versus delayed installationof a three-phase feeder. The engineer can per-form a similar economic comparison for the UDsystem he or she is designing.

DIRECT-BURIED VERSUSPLACEMENT IN CONDUITAt some point, most cables need to be replacedbecause of a cable failure or external damage.Replacing cable in a conduit system is less ex-pensive than replacing direct-buried cable anddoes not disturb the ground surface. However,the initial installation costs are higher than thosefor direct-buried cable. To determine which sys-tem is more economical, the engineer needs to

1Future Upgradesand Replacements

A UD system design

should provide for

future upgrades.

20 – Sect ion 1

perform an analysis similar to the one describedlater in the Direct-Buried Versus Cable in Conduitsubsection. This evaluation is difficult because itmust quantify the expected life of the cable.A conduit system can provide some benefits

that are difficult to assign a value to. A conduitsystem does provide some mechanical protec-tion to the cable and, therefore, could help pro-long cable life in areas with rocky soils or areas

congested with other utilities. If a dig-in shouldoccur, however, the conduit system will be moredifficult to repair. Conduit systems may also re-quire larger cable sizes to offset de-rating factorsas a result of cable heating. Conduit can alsoprotect cable from gophers and prairie dogs;therefore, conduit use in rodent-infested areaswill likely prolong cable life.

1

EconomicComparisonof SystemConfigurations

To design an underground distribution system,the cooperative engineer needs to compare vari-ous system configurations. Points of comparisoninclude the following:

• Service reliability,• Present and future load requirements,• System maintenance and operation, and• Economics.

Economics is not usually the deciding aspectwhen comparing different configurations. How-ever, being aware of the different system costscan help the cooperative engineer make eco-nomically sound design decisions.The following examples compare several sys-

tem configurations and show suitable methods forcalculating the relative economics of each. Someof these economic evaluations compare only ini-tial costs—the purchase cost of the materials andthe installation cost for placing these materialsinto service. Other evaluations consider initial andfuture costs—operating, maintenance, and re-placement costs. Evaluations that consider future

Additional Installed InstalledItem Quantity Unit Cost Total Cost

Single-Phase Riser Assembly, 25 kV 1 $ 460.00 $ 460.00

Trench and Backfill 500 ft 3.00 1,500.00

1/0 AWG A1, 25-kV 500 ft 2.50 1,250.00Underground Cable

Elbow Terminator 1 63.00 63.00

Elbow Arrester 1 237.00 237.00

Feed-Through Standoff 1 175.00 175.00

TOTAL $ 3,685.00

TABLE 1.3: Additional Materials for an Open-Loop System.

costs require use of a carrying charge. The carry-ing charges are annual payments needed to sup-port construction funds, including loan interest,taxes, and insurance. The examples in this sec-tion use a carrying charge of 12 percent. How-ever, when doing comparisons, a carrying chargeshould be selected appropriate to current econom-ics. Only a few examples consider an inflation rate.The inflation rate used is three percent per yearand is not included in the carrying charges. Again,an appropriate value needs to be selected.The installed-material costs used in these ex-

amples can vary significantly from region to re-gion. Therefore, the examples should be used asguidelines only. Economic decisions should bebased on the cooperative’s own cost data andnot on the costs shown in this subsection.

LOOP VERSUS RADIALAs noted earlier in this section, an open-loopsystem provides better system availability than acomparable radial system does. However, anopen-loop system requires additional under-ground facilities—at a minimum, those listed inTable 1.3. This table also shows the additionalcosts of these materials. The single-phase riserassembly listed in Table 1.3 includes all materials(conduit, cable terminations, surge arresters, andfused disconnect switches) for terminating un-derground cable on a riser pole. This assemblydoes not include the pole. The riser assembly insubsequent tables is defined in the same way.Because an open-loop system always re-

quires more materials than a similar radial sys-tem, the initial cost is greater than that of a ra-dial system. In the following examples, this costdifference is calculated for several types of un-derground systems.


SubdivisionsSubdivisions usually have a high consumer den-sity. A cable failure here can interrupt power tomany consumers. As noted, power can be re-stored to these consumers much faster on anopen-loop system than on a radial system. For-tunately, most subdivision layouts can be easilyadapted to the installation of an open-loop sys-tem by extending the underground cable fromthe last transformer to a second riser pole or un-derground feeder source.To illustrate this, a 37-lot subdivision is shown

in Figure 1.17. The approximate cost for a radialsystem is $37,145. The additional materials foran open-loop system are highlighted and areconsistent with those listed in Table 1.3. This in-creases the project cost by $3,685, an additionalcost of approximately $100 per lot. Assuming acarrying charge of 12 percent and an amortiza-tion period of 20 years, this $100 investment hasa levelized annual cost of $13.40 per lot. To pro-vide a more reliable electric system through aloop design, the cooperative will spend $13.40 ayear for each consumer in the subdivision.

This incremental cost for an open-loop systemcould decrease considerably for a large subdivi-sion. For example, consider a 100-lot subdivisionwith lot sizes similar to those in Figure 1.17. Thecost for installing underground facilities will alsobe similar, about $1,000 per lot, so the projectcost would be $100,000 for a radial system. If anopen-loop system can be established with 500or fewer feet of cable, then the additional costremains $3,685. However, instead of $100 perlot, the cost is $36.85 per lot, with a levelizedannual cost of only $5.20 per consumer.In both of these examples, the cooperative

can provide a more reliable system with an ad-ditional investment of 10 percent or less. Thisimprovement will increase consumer satisfactionand promotes a better relationship between thecooperative and the consumer.

Single Residential ConsumerIt is usually practical to install an open-loop sys-tem for a subdivision. In contrast, an open-loopsystem to serve a single residential consumermay not be practical. For example, consider a

1

FIGURE 1.17: Open-Loop System, 37-Lot Subdivision.

50 50 50 kVA

50

OLDCASK

WAY

NEW DOVER ROAD

400' 400' 400'

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROW

285'

500'

460'460'

560'

560'

520'

50

N.O.

50

50 50 37.5

Legend

Single-Phase, Primary Voltage, UD Cable

Three-Phase Overhead Line


Single-Phase, Pad-Mounted Transformer

22 – Sect ion 1

single residential consumer served by 500 feet of1/0 AWG Al primary underground cable. Figure1.18 shows this radial system and also highlightsthe materials required for an open-loop system.The radial system costs $4,792. Conversion to anopen-loop system requires the same materialslisted in Table 1.3, at a cost of $3,685. Here, anopen-loop system costs an additional 77 percent

1

FIGURE 1.18: Open-Loop System, SingleResidential Consumer.

N.O.500’

500’

Riser PoleRiser Pole

Legend





1/0 AWG A1, 25-kV Underground Cable 500 ft $ 2.50 $ 1,250.00


Feed-Through Standoff 1 175.00 175.00


25-kV O.D. Termination 1 66.00 66.00

Cutout 1 73.00 73.00

Riser Pole Arrester 1 89.00 89.00

TOTAL $ 1,953.00

Note. O.D. = outside diameter

TABLE 1.4: Sample Spare Cable Cost, Single Residential Consumer.

of the cost of the radial system, a substantial in-crease over the 10 percent additional cost for thesubdivision.A more economical system for a single cus-

tomer would be a spare cable placed in thesame trench and on the same riser pole. Thecost of a spare cable with terminations and ar-resters is shown in Table 1.4.This reduces the additional cost to $1,953,

which is 41 percent of the total project cost.However, this system is less reliable than is anopen-loop system with separate trenches. Be-cause the spare cable is in the same ditch as thenormal feed cable, both cables are exposed tosimultaneous damage during a dig-in. The open-loop system in Figure 1.18 has two separatetrenches; therefore, a dig-in will usually damageonly one cable. Likewise, placing both cables inthe same riser exposes both cables to damagewhenever the pole is damaged.Instead of serving only one consumer, a single

transformer may serve several consumers. Al-though the cost for an open-loop or spare-cablesystem will be the same, the cost is dividedamong more consumers. If the transformer isserving six consumers, then the cost drops to$614 per consumer for an open-loop system,and $326 per consumer for a spare-cable system.For these situations, the cooperative must de-

cide if the benefits of improved reliability makethe open-loop or spare-cable system a practicalchoice. Factors entering into this decision shouldinclude the type of customer and the difficulty ofeffecting repairs in a timely manner.

Commercial ConsumersCommercial consumers are a very diverse group,ranging from small single-phase consumers tolarge three-phase consumers. For this reason,there is not a single simple example to show aneconomic comparison of a loop versus radialsystem. Instead, the cooperative engineer needsto examine each case to determine the cost ofthe desired level of reliability. As a guideline forthis evaluation, the following example will com-pare the costs of a radial system, an open-loopsystem, and a spare-cable systemThe example in Table 1.5 considers a 500-foot

radial feed to a 300-kVA pad-mounted transformer.This system provides a 277/480-Volt four-wire


It is often helpful to consider the cost per kilo-watt (kW). Doing so also provides a way to com-pare residential and commercial costs. For exam-ple, assume this three-phase installation has aload of 225 kW and the 37-lot subdivision has adiversified load of 7 kW per lot for a total of 259kW. For purposes of comparison, each singleresidential consumer is assumed to have a peak(non-diversified) load of 15 kW. Table 1.6 com-pares the added cost per kilowatt for installingan open-loop system and a spare cable system.Providing an open-loop system for the single

commercial consumer costs 2.5 times that for theresidential consumer in a small subdivision.However, for the installation of a spare cable, asingle residential installation costs nearly 15times as much per kilowatt.If the open-loop three-phase system serves

several commercial consumers, then the addi-tional cost per kilowatt would decrease. Anopen-loop system that serves three 225-kW de-liveries has an additional cost of $11.86/kW in-stead of $35.59/kW. Therefore, an open-loopsystem for several three-phase consumers ismore practical than is an open-loop system for asingle three-phase consumer.

Other Options to ConsiderIn addition to an open-loop design and sparecable design, other options may be consideredfor service to particular consumers or for somecooperatives whose underground installation en-vironment requires other strategies. In some cas-es, it may be economically prudent to install theprimary cable in duct to a single commercial orresidential customer to simplify cable replace-ment in case of failure. This would, of course,depend on the length of the primary cable later-al, the likelihood of future paving over the cableroute, and the rock or debris content of the pri-mary cable route excavation. A similar strategywould be to place an empty capped duct along-side the primary cable in the trench, or to installa cable-in-conduit system for selected installa-tions. These options, in addition to the spare ca-ble installation, may be the most economical inthe long-term because retrenching a cable routeafter the site has developed is many times moreexpensive that the original trenching.

1Installed Installed

Item Quantity Unit Cost Total Cost

Three-Phase Riser Assembly, 25 kV 1 $ 1,332.00 $ 1,332.00

Trench and Backfill 500 ft 3.00 1,500.00

1/0 AWG A1, 25-kV Underground Cable 1,500 ft 2.50 3,750.00

24.9/14.4-kV – 480/277-V, 1 6,505.00 6,505.00300-kVA Transformer



Bushing Inserts 3 57.00 171.00

Transformer Pad 1 364.00 364.00

TOTAL $ 14,522.00

TABLE 1.5: Sample Radial System Cost, Commercial Consumer.

Consumer Type Open-Loop System Spare Cable System*

Residential $3,685/259 kW = $14.22/kW $1,953/15 kW = $130.02/kW

Commercial $8,007/225 kW = $35.59/kW $1,953/225 kW = $8.68/kW

*Spare cable system usually practical only for single transformer installations.

TABLE 1.6: Additional Cost Per Kilowatt, Open-Loop and SpareCable Systems.

service to a three-phase consumer. Table 1.5shows the cost of a radial system to be $14,522.An open-loop system requires an additional

riser assembly, a second trench, and a separatethree-phase run of underground primary cable.These additional materials will cost $8,007, thusincreasing the radial system cost by 55 percent.A second option places one spare cable in

the same trench as the radial feed. This singlespare cable does not provide total redundancyfor the three-phase cable, but would be useful ifone phase of the circuit faulted. The spare cablehas terminations and arresters at each end. Thecost of this option is $1,953, as shown in Table1.4. Instead of 55 percent, this option is only a13 percent increase over the radial cost. Asnoted before, this system is less reliable than anopen-loop system because the spare cable couldbe damaged by a fault in an adjacent cable, adig-in, or damage to the riser pole.

24 – Sect ion 1

THREE-PHASE VERSUS SINGLE-PHASEThe decision to install three-phase facilitiesinstead of single-phase is usually based onthe following:

• Three-phase load requirements,• Load balancing, and• Sectionalizing and protection requirements.

1

FIGURE 1.19: Single-Phase Sub-Feeder.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

BRIDGEHA

MWAY

CHARINGT

ONCT.

IPIP

Riser Pole Riser PolePhase T

wo

SR 1435(100'

ROW)

ROW

ROW

ROW

ROW

Legend

1/0 AWG, 25-kV, UD Cable

Single-Phase Sectionalizing CabinetIP

Installed InstalledItem Quantity Unit Cost Total Cost

Single-Phase Riser Assembly, 25 kV 2 $ 460.00 $ 920.00

Trench and Backfill 1,600 ft 3.00 4,800.00


Single-Phase Sectionalizing Cabinet 2 2,608.00 5,216.00

Cabinet Pad 2 217.00 434.00

1/0 AWG Terminations 8 66.00 528.00

TOTAL $ 15,898.00

TABLE 1.7: Single-Phase Sub-Feeder Cost.Although economics is not the only deciding

factor, it is useful to know the cost difference be-tween installing single- and three-phase systems.As an example, consider a 1,600-foot under-ground sub-feeder of 1/0 AWG A1 25-kV cable.Figure 1.19 shows a single-phase sub-feederwith two single-phase sectionalizing cabinets.The sectionalizing cabinet allows the sub-feederto feed through and also provides two fusedtaps. This cabinet costs about $2,600. The totalproject cost is $15,898, or $9.94 per foot, asshown in Table 1.7.The cost for a similar three-phase sub-feeder

increases considerably. Figure 1.20 shows athree-phase sub-feeder with two three-phasesectionalizing cabinets. The three-phase section-alizing cabinet has three-phase group-operatedswitches on the incoming and outgoing sub-feeder cables. It also has two sets of three-phasefused taps. This cabinet costs $10,000, and thetotal project cost is $41,752 or $26.10 per foot.Table 1.8 shows these costs. For this example,a three-phase sub-feeder is 2.6 times the cost ofa single-phase sub-feeder.

.


This comparison rather conclusively demon-strates that the decision to install a three-phasesub-feeder should not be made lightly. How-ever, if future development plans may requirethe addition of a three-phase feeder along thesame route within a few years, the comparisonchanges dramatically. The delayed installation ofthe underground three-phase line will require

1

FIGURE 1.20: Three-Phase Sub-Feeder.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

CHARINGT

ONCT.

3P3P

Riser Pole Riser PolePhase T

wo

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROW

Legend


Single-Phase Sectionalizing Cabinet3P


Three-Phase Riser Assembly, 25 kV 2 $ 1,332.00 $ 2,664.00

Trench and Backfill 1,600 ft 3.00 4,800.00


Three-Phase Sectionalizing Cabinet 2 10,216.00 20,432.00

Cabinet Pad 2 400.00 800.00

1/0 AWG Terminations 16 66.00 1,056.00

TOTAL $ 41,752.00

TABLE 1.8: Three-Phase Sub-Feeder Cost.trenching in established (landscaped) yards.Trenching in an established yard is very costly.The cooperative must remove sod and obstruc-tions (fences, shrubbery, and utility buildings)before trenching. After trenching, the coopera-tive will need to replace sod or reseed. All thiswork increases the trenching cost from $3 perfoot to $8 per foot.Assume a three-phase feeder is installed five

years after the single-phase feeder is installed.The trenching cost is $8 per foot, an increase of$5 per foot over the cost shown in Table 1.8.Therefore, the trench and backfill cost increasesby $8,000, and the total future cost to install thisthree-phase feeder is $49,752. With a carryingcharge of 12 percent, this cost has a presentworth of $28,229. This cost added to the cost ofa single-phase sub-feeder adds up to a presentworth of $44,127. These results show that ini-tially installing a three-phase sub-feeder costsless than does delaying the three-phase installa-tion. In addition, the conversion of the feederwill require consumer outages that would havebeen avoided if the three-phase installation had

.

BRIDGEHA

MWAY

26 – Sect ion 1

level of system components.For an underground distribu-tion system, these componentsare the following:

• Underground primary cable,• Cable terminators,• Pad-mounted transformers,• Sectionalizing equipment,• Transformer bushing wellinserts, and

• Surge arresters.

The changeout of thesecomponents at the time ofvoltage conversion is very ex-pensive and requires either along outage or a series ofshorter outages. This is partic-ularly true of cable replace-ment in established subdivi-sions. Recent surveys showthat the labor for cable re-placement often costs $8 perfoot or more. In an attempt toavoid the excessive cost of ca-ble replacement, 25-kV cableand terminations could be in-stalled initially. Doing so doesincrease the initial materialcost over that for 15-kV cableand components. However,the labor cost remains thesame. In light of the relativelylow incremental cost for highervoltage cables and accessories,it is generally advisable to in-stall a cable suitable for anydistribution voltage expectedfor the area.For an economic analysis,

consider the 37-lot subdivisionof Figure 1.17. Table 1.9shows the increase in materialcost to be $3,017, or $0.75 perfoot. Determining the futurevalue of this additional invest-ment requires use of a com-pound amount factor.

1

25-kV 15-kV Unit Cost Total CostItem Unit Cost Unit Cost Increase Quantity Increase

1/0 AWG A1 Underground Cable $ 2.28/ft $ 1.69/ft $ 0.59/ft 4,045 ft $ 2,387.00

Elbow Terminator $ 36.00 $ 24.00 $ 12.00 18 216.00

Bushing Insert 48.00 25.00 23.00 18 414.00

Riser Terminator 30.00 30.00 0.00 2 0.00

TOTAL $ 3,017.00

TABLE 1.9: 25-kV Versus 15-kV Cable and Components.

25-kV 15-kV Unit Cost Total CostItem Unit Cost Unit Cost Increase Quantity Increase

50-kVA Transformer $ 1,393.00 $ 1,160.00 $ 233.00 8 $ 1,864.00

37.5-kVA Transformer 1,349.00 1,066.00 $ 282.00 1 283.00

TOTAL $ 2,147.00

TABLE 1.10: Added Cost of Dual-Voltage Transformers.

Unit Quantity Total CostItem Labor Cost Unit Cost Salvage Installed Removed Increase

50-kVA, 7.2-kV $ 94.00 $ 0.00 $ (580.00) — 8 $ (3,888.00)Transformer

37.5-kVA, 7.2-kV 94.00 0.00 (533.00) — 1 (439.00)Transformer

50-kVA, 14.4-kV 94.00 1,574.00 — 8 — 13,344.00Transformer

37.5-kVA, 14.4-kV 94.00 1,525.00 — 1 — 1,619.00Transformer

TOTAL $ 10,636.00

TABLE 1.11: Voltage Conversion Cost at Year 10.

been made initially. Therefore,if future loads may require athree-phase sub-feeder, the co-operative should strongly con-sider installing it as part of theinitial installation.

FUTURE VOLTAGE CONVERSIONConversion to a higher distrib-ution system voltage requiresan increase in the insulation

Where a future

voltage conversion is

possible, it is wise to

install 25-kV instead

of 15-kV cable.


If one assumes a voltage conversion in 10years and a carrying charge of 12 percent, thecompound amount factor is 3.1058. The initialinvestment of $3,017 has a future value of$3,017 × 3.1058 = $9,370, or $2.32 per foot. Thisamount is approximately equal to the presentcost of 1/0 AWG Al, 25-kV underground cable. Itis very unlikely that this amount will cover eventhe purchase cost of the cable in 10 years. For avoltage conversion in 20 years, the initial invest-ment of $3,017 has a future value of $3,017 ×9.6463 = $29,103, or $7.19 per foot. This amountis less than the present labor cost ($8) for cablereplacement. Therefore, in areas where a futurevoltage conversion is possible, installing 25-kVcable instead of 15-kV cable is a wise investment.Another option to consider is installing dual-

voltage transformers along with the 25-kV cableand components. The dual-voltage transformers aremore costly than the 7.2-kV transformers. How-ever, the labor cost to install either transformeris the same. For the 37-lot subdivision, the totalmaterial cost increase for installing dual-voltagetransformers is $2,147, as shown in Table 1.10.Again, consider a voltage conversion 10 years

after the initial installation. Table 1.11 shows thecost at the time of conversion assuming an infla-tion rate of three percent per year and a 50 per-cent salvage on the removed transformers.Determining the present worth of this total re-

quires a present worth factor. For a carryingcharge of 12 percent and a conversion at 10years, this factor is 0.322. Therefore, the trans-

1former changeout cost of$10,636 has a present worthof $3,425. The present worthof installing dual-voltagetransformers is $2,147, whichmakes it the economicalchoice.Table 1.12 shows a similar

analysis for a voltage conver-sion at 20 years instead of10 years. The assumed infla-tion rate is three percent peryear and the salvage value onthe removed transformers is30 percent.For a carrying charge of 12

percent, the present worth fac-tor at 20 years is 0.1037. The transformer change-out cost of $16,347 has a present worth of $1,695.On the basis of this analysis, it is more economi-cal to change out the transformers in the futurerather than install dual-voltage transformers.These economic analyses show that it is im-

portant to plan for future voltage conversions. Ifa voltage conversion is planned within 10 yearsof the initial installation, then the cooperativeshould install 25-kV cable, 25-kV components, anddual-voltage transformers. For conversions occur-ring after 10 years, the cooperative should install25-kV cable and components. To see if dual-volt-age transformers are economically feasible, thecooperative engineer will need to do an analysissimilar to that shown in Tables 1.10 and 1.12.

FRONT VERSUS REAR PROPERTYAs covered earlier in this section, consumers andthe utility often disagree about placement of elec-tric facilities. The utility often prefers to place fa-cilities along the front property line where theyare easier to maintain and operate, thus provid-ing better reliability. In contrast, consumers oftenprefer placing facilities along the rear propertyline. This conflict will rarely, if ever, be solvedby an economic analysis. However, cost is al-ways an aspect to consider. The following exam-ples show a method to compare the cost offront-lot versus rear-lot placement of facilities.The economics of front versus rear place-

ment will vary significantly depending on thesubdivision lot layout. The 37-lot subdivision of

Unit Quantity Total CostItem Labor Cost Unit Cost Salvage Installed Removed Increase

50-kVA, 7.2-kV $ 115.00 $ 0.00 $ (348.00) — 8 $ (1,864.00)Transformer

37.5-kVA, 7.2-kV 115.00 0.00 (320.00) — 1 (205.00)Transformer

50-kVA, 14.4-kV 115.00 1,938.00 — 8 — 16,424.00Transformer

37.5-kVA, 14.4-kV 115.00 1,877.00 — 1 — 1,992.00Transformer

TOTAL $ 16,347.00

TABLE 1.12: Voltage Conversion Cost at Year 20.

28 – Sect ion 1

1

FIGURE 1.21: Front Property Placement.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

BRIDGEHAMWAY

CHARINGT

ONCT.

420'400'

5050

50 50

640'

605’

605'

400'

37.5

37.5

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROWLegend


600-V Service Cable


FIGURE 1.22: Back Property Placement.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

CHARINGT

ONCT.

50

75

50

75

400'

160'180'

300'

240'

37.5

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROWLegend


600-V Service Cable


.

BRIDGEHAMWAY

.


Figure 1.17 shows front-lot placement. For thisparticular subdivision, placement along the rearlot lines will actually require more cable andincrease the total project cost. For this type of sub-division, front-line placement is a practical choice.In contrast, Figures 1.21 and 1.22 show a subdi-

vision where lots share back property lines. Withthis type of lot arrangement, placement along therear property lines requires less cable and fewertransformers. In this particular example, place-ment along the front property line requires 1,886additional feet of cable and one additional pad-mounted transformer. These extra materials in-crease the project cost by $11,496, or 75 percent.Most subdivisions will be a combination of the

two extremes shown in Figures 1.17 and 1.22.Because subdivision layouts differ, an accuratecomparison of costs requires a case-by-case study.Calculating the installed project cost is straight-forward; however, it is difficult to calculate thecost advantage of operating and maintaining fa-cilities along the front-lot lines. As a result, it isimpossible to set a dollar amount on the reliabil-ity and operational convenience gained by plac-ing facilities along the front-lot lines.

DIRECT-BURIED VERSUS CABLE IN CONDUITMany utilities are now replacing undergroundcable that was installed only 15 to 20 years ago.Much of this cable is direct buried. To replace itwill require opening a new trench or tunnelingwith long-distance boring equipment. Both ofthese methods are expensive:

• Trench and backfill labor costs are about$8 per foot.

• Long-distance boring costs are about$9 to $10 per foot.

These costs will vary significantly dependingon soil conditions, other utility congestion, land-scape, and homeowner obstacles.One way to reduce these cable replacement

costs is to install cable in a conduit system. Whenthe cable is in a conduit system, the replacementcost is the cost of pulling out the failed cable andpulling in the new cable plus the cost of the newcable. The soil does not have to be disturbedand other utilities do not have to be located andavoided. Cost savings are tremendous.The following example compares the cost of

direct-buried, PVC rigid conduit with high-density

polyethylene (HDPE) flexible cable in conduit.Because the price of conduit and cable fluctu-ates, it is important that the cooperative engi-neer perform an economic analysis based onthis example but using current costs. In addition,the cost for replacement of direct-buried cablewill vary greatly. If $8 per foot is not reasonable,the engineer needs to insert an appropriate cost.This example uses the 37-lot subdivision of

Figure 1.17. Tables 1.13, 1.14, and 1.15 show thepresent, 25-year replacement, and 30-year replace-ment costs for the three options. This long-termanalysis includes an inflation rate of three per-cent per year. Therefore, the cost to replace di-rect-buried cable will be as follows:

These costs are shown in Table 1.13 as Trench,Backfill, Restore Surface.A present worth factor needs to be used to

compare these three options. For a carryingcharge of 12 percent, the single payment presentworth factor from standard tables for 25 years is0.0588 and for 30 years is 0.0334. For example,for HDPE flexible conduit, the 25- and 30-yearreplacement costs are the following:

Table 1.16 summarizes the present worth foreach option.For cable replacement at 25 years, a flexible

conduit system has the lowest present worthand is the most economical choice. For cable re-placement at 30 years, a direct-buried system isthe most economical. However, a small changein the cost for cable replacement can affect theeconomic choice. For example, if the cost to re-place direct-buried cable is $10 per foot insteadof $8 per foot, then the 25-year cost is $10(1.75)= $17.50 per foot, and the 30-year cost is $10(1.90)= $19.00 per foot. Thus, the total values in Table1.13 change to $88,505 at 25 years, and $96,069at 30 years.

1

$14.00 per foot ($8.00 per foot × 1.75) at 25 years$15.20 per foot ($8.00 per foot × 1.90) at 30 years

$24,675 + .0588($20,185) = $25,862$24,675 + .0334($21,924) = $25,407

30 – Sect ion 1

1Item Quantity Unit Installed Cost Total Installed Cost

Trench and Backfill 4,045 ft $ 3.00/ft $ 12,135.00

Present Cost 1/0 AWG A1, 25-kV Underground Cable 4,045 ft 2.50/ft 10,113.00

TOTAL $ 22,248.00

25-YearTrench, Backfill, Restore Surface 4,045 ft $ 14.00/ft $ 56,630.00

Replacement1/0 AWG A1, 25-kV Underground Cable 4,045 ft 4.38/ft 17,717.00

TOTAL $ 74,347.00

30-YearTrench, Backfill, Restore Surface 4,045 ft $ 15.20/ft $ 61,484.00


TOTAL $ 80,698.00

TABLE 1.13: Option 1—Direct-Buried Cable.

Item Quantity Unit Installed Cost Total Installed Cost


Present Cost2-Inch Conduit 4,045 ft 1.55/ft 6,270.00

1/0 AWG A1, 25-kV Underground Cable 4,045 ft 2.60/ft $ 10,517.00

TOTAL $ 28,922.00

25-YearRemove Cable From Duct 4,045 ft $ 0.44/ft $ 1,780.00


TOTAL $ 20,185.00



TOTAL $ 21,924.00

TABLE 1.14: Option 2—PVC Rigid Conduit.

For the 30-year replacement, these values resultin a present worth of $22,248 + .0334($96,069)= $25,457.Therefore, the flexible conduit is the economical

choice for replacement at 30 years. For this reason,it is important for the engineer to select an appro-priate cable replacement cost for the economicanalysis. Of course, this economic analysis couldnot assign a monetary value to the following:

• Consumer inconvenience and irritation thatresults from trenching across establishedlawns, and

• Added cable protection provided by aconduit system.

Another consideration for this analysis is thetype of native soil. If the soil is rocky, it is notsuitable for backfill of a direct-buried cable. Inthis case, select fill material must be used for atwo-inch minimum of cable bedding and a four-inch cable cover. The cost of this select fill mate-rial can substantially increase the initial projectcost for a direct-buried system. In contrast, the useof a conduit system, flexible or rigid, protectsthe cable from rocky soils; in most cases, select


backfill is not required. Therefore, the initial pro-ject cost for the two conduit systems will not in-crease. Adverse soil conditions can quickly shiftsystem economics to favor conduit installations.Although this analysis is based on a small 37-lot

subdivision, the results show that a conduit sys-tem can be an economical choice. The prices forconduit, trenching, surface restoration, and long-distance boring vary from region to region. To

1Item Quantity Unit Installed Cost Total Installed Cost


Present Cost Cable in Conduit 4,045 ft 3.10/ft 12,540.00

TOTAL $ 24,675.00



TOTAL $ 20,185.00



TOTAL $ 21,924.00

TABLE 1.15: Option 3—Cable in HDPE Flexible Conduit.

Present Worth

Installation Method 25-Year Replacement 30-Year Replacement

Direct Buried $ 26,620.00 $ 24,943.00

PVC Rigid Conduit 30,109.00 29,654.00

HDPE Flexible Conduit 25,862.00 25,407.00

TABLE 1.16: Present Worth of Cable Installation Options.get accurate results, each cooperative will needto conduct a similar analysis using its cost data.

SEPARATE SERVICES VERSUSSECONDARY PEDESTALSIn a residential subdivision, a single pad-mountedtransformer often provides electrical service toseveral consumers. Service may be provided di-rectly from the transformer or from a secondarypedestal. Figure 1.23 shows both methods. Thearrangement that uses a secondary pedestal isless reliable than direct service from the trans-former. A cable fault on the secondary cable willinterrupt power to multiple consumers. In con-trast, a cable fault on an individual service willinterrupt power to that consumer only.This analysis compares the initial installation

cost only. Table 1.17 lists the cost of providingseparate services as shown in method A of

200’

150’Transformer

#6

4/0 4/0

Method A—Seperate Services

250’150’

10’

50’ 50’

#6

4/0 4/0

4/0Transformer

Method B—Secondary Pedestal

Secondary Pedestal

FIGURE 1.23: Methods for Providing Secondary Service.

32 – Sect ion 1

1Quantity Installed Installed

Item (ft) Unit Cost Total Cost

Trench and Backfill 300 $ 3.00/ft $ 900.00

4/0, 600-V Triplexed Cable 400 1.25/ft 500.00

No. 6, 600-V Triplexed Cable 200 0.25/ft 50.00

TOTAL $ 1,450.00

TABLE 1.17: Separate Service Cables.

Quantity Installed InstalledItem (ft) Unit Cost Total Cost

Trench and Backfill 300 $ 3.00/ft $ 900.00

4/0, 600-V Triplexed Cable 300 1.25/ft 375.00

No. 6, 600-V Triplexed Cable 10 0.25/ft 2.50

Secondary Pedestal 1 172.00 172.00

Insulated Connectors 3 14.00 42.00

TOTAL $ 1,491.50

TABLE 1.18: Secondary Pedestal.

Figure 1.23. The separate services do share acommon trench along the front property line.Method B of Figure 1.23 shows the use of a sec-

ondary pedestal. This cost is shown in Table 1.18.As this example shows, the use of separate

service cables is often the economical choice forlots located on the same side of the road as thetransformer if the lots are developed at the sametime. However, the use of a secondary pedestalacross the road from the transformer may be theeconomical choice since it requires trenching ortunneling across the road in only one location.

UD LossEconomics

The inevitable loss of some of the power deliv-ered through underground cables is an expensefor the cooperative. Optimal economic design ofthe system requires that this expense be knownand evaluated.Cable losses are classified as either load-de-

pendent or non-load-dependent. For UD cables,most of the loss is load-dependent; it is only inunusual circumstances that non-load-dependentloss becomes significant. The cost of losses isderived from a combination of peak-loaddemand costs and accumulatedannual energy costs. A thor-ough coverage of the types oflosses and their costs to coop-eratives is contained in theNational Rural ElectricCooperative Association’sDistribution System LossManagement Manual(NRECA Research Project 90-7).

COST OF LOSSESIn a sample analysis of the cost of losses ondistribution primary lines, the DistributionSystem Loss Management Manual provides costfigures for a typical cooperative. The samplecooperative purchases wholesale power at $10per kW per month at a 100 percent ratchet, andthe wholesale energy rate is $0.03 per kilowatt-hour (kWh).Non-load-dependent losses are constant as

long as the cable is energized. Load-dependentlosses change with the squareof the loading level, whichmakes it difficult to determinetheir average level. A quantityreferred to as a loss factor isused to estimate the averageof load-dependent losses whentheir peak value is known.A value of 0.3 (30 percent)is suggested as typical for

For UD cables,

most power loss is

load dependent.


primary distribution lines when calculatingloss factors.The cost per peak kilowatt for line losses for

the sample cooperative is then determined asfollows:

The resulting expense per kilowatt of loss canbe used to quickly estimate the savings that willresult from using UD designs that operate atlower losses. The loss savings can be comparedwith the annual carrying charges on the extra in-vestment costs required to achieve lower losses.This type of economic comparison is discussedin detail in the Distribution System Loss Manage-ment Manual.

CABLE SYSTEM LOSSESAn essential step in the economic evaluation oflosses is calculating the expected electrical lossesfor alternative designs. For a primary UD cable,losses occur in the conductor, sheath, and di-electric, and as a result of cable charging current.

Primary Cable Conductor LossesThe losses resulting from load current interact-ing with the conductor resistance (I2R losses)are by far the most significant losses in primaryUD cables. For a run of three-phase cable, these

1

Annual Demand Costper kW of Peak Losses

$10/kW/month × 12 months = $120/kW

Annual Energy Cost per kWof Non-Load-Dependent Peak Losses8,760 hours × $0.03/kWh = $263/kW

Annual Energy Cost per kWof Load-Dependent Peak Losses

0.3 × 860 hours × $0.03/kWh = $79/kW

Total Annual Cost per kWof Non-Load-Dependent Peak Losses$120/kW + $263/kW = $383/kW

Total Annual Cost per kWof Load-Dependent Peak Losses$120/kW + $79/kW = $199/kW

Equation 1.1

WR=3 I2 R L

where: WR= Total loss, in wattsI = Load current, in amperesR = Phase conductor resistance, in

ohms per kilofoot (kft)L = Circuit length, in kft

losses are calculated by the formula shown inEquation 1.1.

Primary Cable Sheath LossesThe normal UD practice is to ground cablesheaths at both ends. When this is done onthree-phase cable runs, a small amount of circu-lating current will be induced in the cablesheaths. The flow of this current produces asmall loss in the sheaths, calculated as shown inEquation 1.2.XM is determined using Equation 1.3.

Equation 1.2

where: WS= Total sheath loss, in wattsI = Load current, in amperesRS = Sheath resistance, in ohms per kftL = Circuit length, in kftXM = Sheath reactance, in ohms per kft

WS =3 I2 RS L X2MR2S + X2M

Equation 1.3

where: XM = Sheath reactance, in ohms per kftS = Center-to-center spacing, in mils,

for equilaterally spaced cablesrM = Mean radius, in mils, to the sheath

for each cable

XM= 0.05292 log10SrM

34 – Sect ion 1

Primary Cable Dielectric LossesVoltage stress on cable insulation produces aslight heating effect that leads to power losses.These dielectric losses can be calculated usingEquation 1.4.The formula in Equation 1.4 shows that di-

electric losses are directly proportional to theproduct of εt and cosφ. Cable engineers refer tothe product εt cosφ as the cable loss factor. Thisuse of the term loss factor is completely differentfrom the use of loss factor earlier in this section.Dielectric losses are a consequence of the cablebeing energized and are, therefore, continuous;whereas the more common use of the term lossfactor deals with losses due to the resistance ofthe conductor and, therefore, vary with the mag-nitude of the load being carried by the cable.

Primary Cable Charging-Current LossesThe capacitance of an underground cable drawscharging current that interacts with the conduc-tor resistance to produce a small loss. If thecable is delivering current to low power factorload, the charging current will be beneficial be-cause its leading nature will cancel out some ofthe lagging load current. Therefore, charging-current losses are of concern for only unloadedcables or those carrying unity power factor loads.The procedure for calculating charging-cur-

rent losses begins with determining the cablecapacitance per phase with Equation 1.5.

1Equation 1.4

where: WD = Total three-phase dielectric loss,in watts

E = Line-to-ground operating voltage,in kV

L = Circuit length, in kftεt = Dielectric constant of the insulationcosφ = Insulation power factor, per unitT = Insulation thickness, in milsD = Conductor diameter, in mils

WD=8.28E2 Lεt cosφ

log102T+DD

Equation 1.5

where: C = Cable capacitance, in nanoFarads(nF) per kft

εt = Dielectric constant of the insulationT = Insulation thickness, in milsD = Conductor diameter, in mils

2T+DD

C = 7.354 εtlog10

Equation 1.6

IC= 0.000377 C E

where: IC = Charging current, in amperes per kftC = Cable capacitance, in nF per kftE = Line-to-ground operating voltage,

in kV

Equation 1.7

WC = R I2C L3

where: WC= Total three-phase charging currentloss, in watts

R = Phase conductor resistance, in ohmsper kft

IC = Charging current, in amperes per kftL = Circuit length, in kft

Data for Cable Loss CalculationsMany items of technical data are needed on thecables involved to calculate losses from theabove formulas. Physical measurements such asdiameter and insulation thickness are usuallyshown on manufacturers’ catalog sheets. Basicelectrical data such as voltage, amperes, andresistance are known from the system or can

Next, charging current per kilofoot of cablelength is calculated with Equation 1.6.

Finally, the charging-current loss is calculatedas shown in Equation 1.7.


easily be found from catalog sheets or standardreferences.The insulation dielectric constant, εt, and

power factor, cosφ, are sometimes difficult todetermine. Manufacturers’ data sheets often donot give these parameters. For pure materialssuch as TR-XLPE, the information may be ob-tained from standard references. However, mostmodern insulation types contain additives thataffect dielectric constant and power factor. To

be sure that the correct values are known, it isusually necessary to contact engineering special-ists on the staff of the manufacturer of each spe-cific cable type. There are often large differencesin values for dielectric constant and power fac-tor among various cable types. The spread invalues is especially pronounced for the powerfactor. In addition, the cable power factor oftenvaries substantially with cable temperature. It isrecommended that, if comparisons are being

1

EXAMPLE 1.1: Cable Loss Calculations.

This example contains typical data; however, don’t use the sample data in actual-case calculations. Foractual situations, consult the cable manufacturer to get accurate data on the cable being used.Table 1.19 shows data and loss calculation results for a typical three-phase cable run. Three insulationtypes are represented at two different temperatures.

@ 25° C @ 50° C

Low-Loss High-Loss Low-Loss High-LossInsulation Type Sample Data TR-XLPE EPR EPR TR-XLPE EPR EPR

(E) Line-to-Ground Operating Voltage in kV 7.2 7.2 7.2 7.2 7.2 7.2

Conductor Size 1/0 A1 1/0 A1 1/0 A1 1/0 A1 1/0 A1 1/0 A1

(D) Diameter in mils 373 373 373 373 373 373

(T) Thickness in mils 220 220 220 220 220 220

(rM) Mean Radius in mils 430 430 430 430 430 430

(S) Center-to-Center Spacing in mils 1,180 1,180 1,180 1,180 1,180 1,180

(R) Resistance in Ω/kft 0.20 0.20 0.20 0.20 0.20 0.20

(RS) Sheath Resistance in Ω/kft 0.60 0.60 0.60 0.60 0.60 0.60

(εt) Dielectric Constant of the Insulation 2.35 2.9 3.27 2.35 2.9 3.27

(cosφ pu) Insulation Power Factor per Unit 0.06 0.25 2.0 0.06 0.30 3.25

(L) Circuit Length in kft 4.0 4.0 4.0 4.0 4.0 4.0

(I) Load Current in Amperes 60 60 60 60 60 60

Conductor Loss, Watts 8,640 8,640 8,640 8,640 8,640 8,640

Concentric Neutral Loss, Watts 38.7 38.7 38.7 38.7 38.7 38.7

Dielectric Loss, Watts 715 3,679 33,184 715 4,414 53,924

Charging Loss, Watts 0.3 0.4 0.5 0.3 0.4 0.5

TOTAL LOSS, Watts 9,394 12,358 41,863 9,394 13,093 62,603

*Insulation Data Courtesy of the Okonite Company

TABLE 1.19. Sample Cable Loss Analysis.

36 – Sect ion 1

made among cable types, the engineer shoulduse only written data obtained from the manu-facturer of that cable type. An excellent sourceof this data is the cable manufacturer’s InsulatedCable Engineers Association (ICEA) QualificationReport for the particular cable construction. Oncethe figures are obtained, compare the data fromdifferent sources to confirm the reasonablenessof the information for a particular cable type.When requesting data from cable manufactur-

ers, be as specific as possible about the databeing requested. Ask the manufacturer for thedata from ICEA qualification tests. Losses shouldbe quoted for a specific temperature, such as 40°C.The loss figures in Table 1.19 show that sheath,

dielectric, and charging-current losses are negligi-ble compared with conductor load-current losses,except in the case of high-loss EPR. However,under light-load or other unusual conditions, therelative values of the three types of losses maybecome more significant. Charging-current loss-es, for example, may become significant for ex-tremely long cable runs because these losses in-crease with the cube of the circuit length.Another important consideration is that small

loss differences among alternative cable typescan accumulate to a significant expense if anextremely large amount of cable is placed in ser-

vice. The dielectric loss differential between nor-mal EPR cable and TR-XLPE cable is approxi-mately 0.22 kW per circuit mile from the resultsshown on the table. Because this loss is non-load-dependent, the annual loss expense permile as calculated above is typically $84 permile (0.22 kW/mile × $383/kW). For 100 circuitmiles of installed cable, this expense comes to$8,400 per year, which no longer seems insignif-icant. However, in a total economic evaluation,the cost of additional dielectric losses ($84 permile) must be compared with any additional lifeexpectancy that might be available from thehigher loss insulation system. Appendix D ofNRECA CRN Project 90-8 provides a method forevaluating cable losses and life expectancy inthe purchasing process.

Secondary Cable LossesFor secondary UD cables, losses other thanload-current-related conductor I2R losses aretruly insignificant. Loss control methods for ap-plication to secondary designs are the same asdescribed in the NRECA Distribution System LossManagement Manual for either overhead or un-derground situations. Appendix B to that manualgives annual kilowatt-hour losses for a selectionof conductor sizes and loading levels.

1This example illustrates how the losses on secondarycables are calculated. Sample data are shown in Table1.20.

The conductor resistance is obtained from standard ref-erences. A conductor temperature of 25°C is assumedfor underground secondary cables that are not heavily

loaded. In this case, a resistance of 0.167 ohms per kftis given by reference tables.

Load on the neutral is assumed to be negligible. There-fore, the conductor distance is 300 feet, and the totalresistance is 0.05 ohms.

Losses at peak load are calculated as follows:

Annual energy losses are determined by using the lossfactor:

EXAMPLE 1.2: Calculating Losses on Secondary Cables.

Voltage of Circuit 120/240-V, single-phase

Circuit Length 150 feet

Conductor No. 1/0 AWG, aluminum

Peak Load 85 amperes

Loss Factor 20%

TABLE 1.20: Sample Secondary Cable Data.

WR = I2 R = 852 × 0.05 = 361 watts

Energy Losses = 0.2 × 8,760 hours × 361 watts= 632,472 watt-hours = 632 kWh


PAD-MOUNTED TRANSFORMER LOSSESThe losses on pad-mounted transformers usedon UD systems are a significant expense. Closeattention to the managementof losses on any type of trans-former is essential to a losscontrol program.As with all types of trans-

formers, losses on pad-mounted transformers are oftwo distinct types. The firstcategory, core losses, is notload dependent and represents a continuous ex-pense whenever the transformer is energized.The second category, winding losses, comprisesload-dependent losses that become especiallyexpensive during peak loads.

Higher efficiency transformers with losses

1

Consider a 50-kVA pad-mounted transformer having 140 watts of core losses and490 watts of winding losses at nameplate load. If this unit is loaded to 60 kVA at peakload, the winding losses will be as follows:

With the annual cost figures given for losses at the beginning of this subsection, theannual costs associated with each type of loss can be calculated as follows:

The total annual cost of the losses associated with operating this transformeris $194.

EXAMPLE 1.3: Typical Costs Associated with Transformer Losses.

Winding Losses = (60 ÷ 50)2 × 490 watts = 706 watts

Core Loss Cost = $383/kW × 0.140 kW = $54Winding Loss Cost = $199/kW × 0.706 kW = $140

approximately 20 percent less than this exampleare available from manufacturers. Use of thehigher efficiency transformer will save about $40

annually, which is enough toamortize about $300 in initialinvestment cost at a 12 percentcarrying charge rate over a 20-year period. Thus, if the higherefficiency transformer can bepurchased for less than a $300price premium over the sam-ple transformer, then it is a

better economic choice in the long run.The Distribution System Loss Management

Manual provides thorough coverage of the issueof transformer losses and the means to controlthe associated expenses to the extent feasible.

DEFERMENT OF TRANSFORMER ENERGIZATIONNew housing developments often require theconstruction of the electric UD system well be-fore most living units are built and occupied.When energized transformers are installed be-fore there are consumers to serve, the non-load-dependent or no-load losses on the transformersrepresent an expense that is uncompensated byrevenue. This expense can be avoided by keep-ing the transformers de-energized until they areneeded. Service to street lights can be concen-trated in a small number of transformers to allowthe de-energization of most of the units in areasnot yet occupied.Installing a de-energized transformer requires

the use of a feed-through stand-off bushingwhich, in most cases, costs about $150. Becausethis bushing can be reused elsewhere after thetransformer is placed in service, the specialbushing cost is equivalent to $20 annually at a12 percent carrying charge rate over a 20-yearperiod. Despite this expense, the avoidance ofcore losses represents a net savings, as shownby Table 1.21.If hundreds of units are involved, the savings

associated with deferred energization could ex-ceed $8,000 annually.For 50- and 100-kVA installations, larger sav-

ings can be achieved by deferring the installationof each transformer not needed for immediateservice by placing a pedestal containing a feed-

Pad-mounted

transformer losses are

a significant expense.

Annual Loss Feed-Through AnnualSize Core Losses Cost at Device Net(kVA) (watts) $383/kW Annual Cost Savings

25 82 $ 31.00 $ 20.00 $ 11.00

50 140 54.00 20.00 34.00

100 260 100.00 20.00 80.00

TABLE 1.21: Savings from Deferred Transformer Energization.

38 – Sect ion 1

through device at the future transformer loca-tion. The cost of the pedestal and device isabout $330, which represents a $40 annual costat a 12 percent carrying charge rate (0.12 × 330= $40). A nonrecoverable labor cost of about$160 is incurred for installing the temporaryfeed-through pedestal and removing it later. Ifthe average deferment time is two years, thiscost is $80 annually. Therefore, the cost for ex-ercising this deferment option is $120 annually($40 + $80).On the plus side, the annual carrying charges

on a transformer are avoided along with the costof core losses. The overall results are summarizedin Table 1.22 for three common transformer sizes.

1These results show that deferred installation

of transformers is not significantly beneficial for25-kVA units. However, the net savings can besubstantial in the case of larger units. If hun-dreds of units are involved, the savings mayexceed $25,000 annually.Simply routing the cable aboveground at

future transformer locations and looping it backinto the trench without cutting it can achieve stilllarger savings. An enclosure is then installed toprotect the above-ground loop. When the timecomes for a transformer to be installed, the cableis de-energized and cut to prepare for the instal-lation of the elbows and transformer. However,special care must be used to avoid excessivecable bending with this type of installation, andthe extra switching that may be required duringthe final transformer installation does representan additional expense.

CONCLUSIONElectrical losses on UD systems represent an ex-pense that should be managed to reduce costs.When alternative UD system designs are consid-ered, it is necessary to estimate the amount ofthese losses and their costs. The techniquesgiven here and in the NRECA DistributionSystem Loss Management Manual provide thenecessary calculation methods.

25 kVA 50 kVA 100 kVA

Transformer Price $ 750.00 $ 1,000.00 $ 1,750.00

Deferred Transformer Carrying Charges $ 90.00 $ 120.00 $ 210.00at 12% (Transformer Price x 0.12)

Deferred Annual Core Loss Cost 31.00 54.00 100.00(from Table 1.21)

Total Deferred Cost 121.00 174.00 310.00

Temporary Equipment Annual Cost 120.00 120.00 120.00

Net Annual Savings 1.00 54.00 190.00

TABLE 1.22: Savings From Deferred Transformer Installation.

Steps for Layoutof a UD System

To help the engineer with layout of a UD sys-tem, this subsection describes eight design steps:

STEP 1: Get the required information.STEP 2: Arrange the service and transformer

layout.STEP 3: Calculate the consumer load and select

proper equipment ratings.STEP 4: Select the primary cable route.STEP 5: Locate sectionalizing equipment.STEP 6: Visit the project site.STEP 7: Obtain all easements.STEP 8: Prepare staking sheets.

STEP 1. GET THE REQUIRED INFORMATIONBefore any design work can be started, theengineer must get certain information fromthe consumer or developer, including thefollowing:

• Site plan with defined lots and utilityeasements,

• Load and voltage requirements,• Project schedules,• Location of other underground utilities,• Reliability needs, and• Final grading plans.


For subdivisions, it is veryimportant to get a copy of thesubdivision plat. This mapshows the lot arrangementsand is necessary for designingthe layout of underground fa-cilities. Appendix D contains aform to use when collectingthis information.This information is rarely gathered in one

brief conversation. Rather, it is usually compiledthrough several conversations and meetings withconsumers, the developer, contractors, and otherutility representatives. It is the engineer’s duty topersevere until all required data are collected infinal form. Although the engineer can plan manyaspects of the project on the basis of preliminaryinformation, a final design should not be releaseduntil all information is collected and verified.Otherwise, the project may encounter unneces-sary construction difficulties, fail to meet con-sumer expectations, or use materials inefficiently.In any of these cases, the cost to the cooperativeand its consumers will be greater than for awell-designed system.

STEP 2. ARRANGE THE SERVICEAND TRANSFORMER LAYOUTCommercial and industrialconsumers usually have heavyloads that can include large-horsepower motors. To limitthe voltage drop and flickerassociated with these loads,the transformer should be nearthose consumers’ deliverypoints. Often the transformeris placed near the building. The engineer shoulduse good judgment and experience in determin-ing the minimum allowable distance betweenthe transformer and the building. Factors affect-ing the distance will include building use, firerating of the exposed wall, presence of wallopenings, vehicle traffic, and other public safetyconsiderations. If the utility or the buildingowner concludes that additional protection iswarranted, such enhancements might be achievedby increased separation, use of “less flammable”fluid in the transformer, or installation of a

barrier wall or an oil absorptionbed around the transformer.In contrast, the typical resi-

dential load does not requirethe transformer to be next tothe house. Rather, the trans-former can be in a central lo-cation and provide service toseveral consumers.

The engineer can begin to arrange this serviceand transformer layout after receiving the subdi-vision plat. Several studies have shown that themost economical arrangement uses the leastnumber of transformers. This design, in turn,means longer service conductor lengths andmore consumers per transformer. However,voltage flicker at the consumer’s delivery pointoften limits the service conductor length. De-pending on lot size, limiting the service conduc-tor length may reduce the number of consumersper transformer. Another limiting factor is thespace in the secondary compartment of thetransformer. Most single-phase pad-mountedtransformers have space for connecting a maxi-mum of eight secondary/service conductors.This includes secondary conductors used to feedstreet and area lights.

In some layouts, a trans-former may serve some lots lo-cated across the street. Aconvenient way to serve sev-eral lots with only one roadcrossing is from a secondarypedestal. The secondarypedestal is supplied by a sin-gle secondary cable from thetransformer (see Figure 1.24).

Unfortunately, this decreases service reliability.A cable fault on the one secondary cable inter-rupts power to all the attached consumers.However, the time required to replace the failedcable will be shorter if the cable is in a conduit.It is also advisable to have cable in conduit forany roadway crossing to eliminate future streetcutting and provide additional protection againstdig-ins.Secondary pedestals are not the ideal method

for serving consumers on the same side of theroad as the transformer. Each of these consumers

1For subdivisions,

get a copy of the

site plan and

recorded plat.

Service conductor

length is often

limited by

voltage flicker.

40 – Sect ion 1

should have a separate service cable from thetransformer. This improves reliability, is oftenmore economical than installing a secondarypedestal (see Economic Comparison of SystemConfigurations earlier in this section) and alsoeliminates maintenance of the secondarypedestal.Figure 1.25 shows a service and transformer

layout for a 75-lot subdivision. This layout fea-tures 13 transformers that serve an average ofsix consumers each. Transformers located alongthe front property lines serve the perimeter lots.The interior lots share back property lines;therefore, it is more economical to serve theselots from transformers located along the rearproperty lines. This combination of front andrear property line placement is often the mosteconomical layout. Because of criteria otherthan economics, the cooperative may allowtransformer placement along the front propertyline only or the rear property line only. Table1.2 lists these other criteria and compares theadvantages and disadvantages of front versusrear line placement.

1

FIGURE 1.24: Road Crossing to Feed Secondary Pedestal.

ELMSTE

ADCT.

Transformer

SecondaryPedestal

4/0

BRIDGEHAMWAY

FIGURE 1.25: Service and Transformer Layout for 75-Lot Subdivision.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

BRIDGEHAMWAY

CHARINGT

ONCT.

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROWLegend

Secondary-Voltage Cable

Streetlight


Note: The three shadedlots indicate the worstlocations for voltage dropand flicker.


STEP 3. CALCULATE THE CONSUMER LOADAND SELECT PROPER EQUIPMENT RATINGSFrom the information collected in Step 1 and theservice and transformer layout of Step 2, the en-gineer can calculate the expected consumerloads. On the basis of the calculated load, theengineer will select the following:

• A secondary cable with adequate capacity,• A transformer with sufficient kVA for thediversified consumer load, and

• A primary cable with ampacity based on theexpected operating conditions.

Information for making these selections iscontained in Section 4, Equipment Loading. Inreviewing the total primary current for the loadto be served, the engineer must select primarycables with the proper ampacity ratings. How-ever, when decisions are made concerning thesetotal primary load currents, care must be takento also maintain load balance among phases onthe feeders serving these loads.After making these selections, the engineer

must check for voltage drop and voltage flickerat the consumer’s delivery point. Appendix Bcontains equations for calculating voltage dropand flicker. The voltage drop must not exceedthe maximum values in Table B.1. Likewise, themagnitude and frequency of the voltage flickermust be within the permissible levels shown inFigure B.2. For a subdivision layout, it is notnecessary to calculate these values for each con-sumer. Instead, the engineer should determine afew worst cases and perform the calculations forthese only. For voltage drop, the worst cases arethe longer secondary/service cables served fromtransformers having a greater number of con-nected consumers. For voltage flicker, the worstcases are a combination of longer secondary/service lengths, larger motors, and smaller trans-former sizes. Figure 1.25 highlights the worstcases for voltage drop and voltage flicker.If the calculated voltage drop exceeds the

limits in Table B.1, the engineer must modify thedesign. Voltage drop is a product of load currentand circuit impedance. For voltage drop at theconsumer’s delivery point, the circuit impedanceconsists of the transformer and the secondary/

service cable impedance. Reducing the load cur-rent or the circuit impedance reduces the volt-age drop. As load current is usually a fixedvalue, the engineer must find ways to reducethe circuit impedance.The engineer can reduce the transformer im-

pedance by selecting the following:

• A unit with a lower impedance, or• A unit with a greater kVA rating.

However, these methods are usually notcost-effective. A low-impedance transformertypically costs more than a standard unit andrequires the utility to stock standard and non-standard transformers. A transformer with agreater kVA rating costs more and also hashigher core (no-load) losses.For residential services, it is more practical to

lower the secondary/service cable impedancerather than the transformer impedance by doingthe following:

• Shortening the cable length,• Increasing the cable size, or• Paralleling cables.

By placing the transformer closer to the con-sumer’s delivery point, the engineer can shortenthe secondary/service cable length. Although theprimary cable length is increased, this approachis often economical for single deliveries, particu-larly those with large secondary/service cables.The larger secondary/service cables can costmore than primary cable. If it is not practical toplace the transformer closer, the engineer canincrease the secondary/service cable size or canparallel two smaller cables.But instead of serving a single delivery, a

transformer in a subdivision will serve multipledeliveries. Therefore, shortening the sec-ondary/service cable lengths in a subdivision re-quires installing additional transformers. Thecost of installing and operating these additionaltransformers may be greater than the cost of in-creasing the secondary/service cable size. Insubdivisions, therefore, it may be more econom-ical to increase the cable size rather than shortenthe cable length.

1

42 – Sect ion 1

Reducing the cable imped-ance also reduces the voltageflicker during motor starting.For large motors, this methodmay not limit the voltageflicker to the permissible levelsshown in Figure B.2. For situa-tions involving polyphase mo-tors, a consumer may use astarting method that reduces the motor inrushcurrent. The engineer needs to review large mo-tors and the proposed starting methods to see ifthe arrangements will cause problems on theelectric system or for other consumers. Onemethod of particular concern is the use of anelectronic “soft” starter. Unlike conventionalmethods, this type of reduced voltage startingproduces harmonics on the electric system. Theharmonics result from chopping the voltage sinewave to reduce the voltage at the terminals ofthe motor.

STEP 4. SELECT THE PRIMARY CABLE ROUTEAfter locating the transformers and services, theengineer must select a primary cable route. The

cable route should be themost efficient way to serveall the transformers. For pro-jects with multiple transform-ers, an open-loop feeder ispreferred. The primary cableroute should be offset at leastone to two feet from anyproperty line. Property owners

often place fences along their property lines andcould damage buried cable placed on the prop-erty line.The route should also minimize conflict with

other buried utilities. One way to accomplishthis is to establish a utility corridor. Within thecorridor, each utility occupies its allocatedspace, which allows each utility to know the ap-proximate location of other utilities. A utility cor-ridor requires a wider easement than the usual10-foot easement for electric facilities only. Utili-ties may find this concept works well in subdivi-sions where the developer has defined a wideutility easement on the subdivision plat.Some developers may ask the cooperative to

locate its facilities within the street right-of-way.

1Offset the primary

cable route at least

1 to 2 feet from any

property line.

FIGURE 1.26: Primary Cable Layout for 75-Lot Subdivision.

OLDCASK

WAY

NEWYAR

MOUTH

WAY

NEW DOVER ROAD

ELMSTE

ADCT.

BRIDGEHAMWAY

CHARINGT

ONCT.

SR 1435 (100' R

OW)

ROW

ROW

ROW

ROWLegend



.


Although this is convenient for the developer, itusually creates future problems for the coopera-tive. These private roads are often released tothe local city or state road system. These gov-ernments have rules about utilities locatedwithin the road right-of-way. Most require theutility to file a right-of-way encroachment, tobury cables at a specified depth, and to meetvery high compaction levels during trench back-fill. When the governing body decides to widenthe road, the cooperative may have to relocateits facilities at its expense. The cooperative canavoid these conflicts by locating its facilities on aprivate right-of-way off the edge of the city,county, or state right-of-way.Finally, the selected cable route should mini-

mize the number of road crossings. A faultedcable section under a road is difficult to repairor replace unless the cable is in a conduit. Aconduit with cable or a spare conduit placed be-neath the road allows the cooperative to replacethe cable without disturbing the road surface.This method is acceptable for use with direct-buried, jacketed primary cable. It should benoted that placing the cable in the conduit willreduce the cable ampacity.Figure 1.26 shows a primary cable route for

the 75-lot subdivision. This particular cable routehas two road crossings.

STEP 5. LOCATESECTIONALIZING EQUIPMENTAfter selecting the primarycable route, the engineer canlocate the sectionalizingequipment, which includesriser poles, junction cabinets,fuse cabinets, and switchgear.These devices are used to pro-vide sectionalizing at desiredpoints within the UD system. Section 3, Under-ground System Sectionalizing, describes thedesirable locations for sectionalizing devices.Utility personnel have to operate and main-

tain these devices; therefore, the equipmentneeds to be in accessible locations. Operatingpad-mounted equipment requires enough work-ing space to move elbow terminators with hotsticks. The minimum working space is the width

1

FIGURE 1.27: Minimum RequiredWorking Space.

Equipment Pad

Clear Working Space

10'0"

of the equipment and 10 feet out from theequipment door as shown in Figure 1.27. Pad-mounted switchgear often has two sets of doorsand, therefore, requires working space on bothsides of the equipment.Another concern is damage from vehicles.

Cars are likely to bump anddamage equipment located inparking lots. If the equipmentcannot be relocated, the coop-erative may have to installsome type of barricade aroundthe equipment. However, thisbarricade must not block theequipment doors or obstructthe required working space.Equipment located along

streets and at intersections can be damaged bysnow removal equipment, particularly if theequipment is covered by snow. Another high-risk area is a crop field. Tall crops can obscurethe equipment, making it invisible to someoneoperating farm equipment. These high-risk areasmust be avoided or adequate protective methodsmust be used to minimize the chance for equip-ment damage.

The minimum working

space extends out

10 feet from the

equipment door.

44 – Sect ion 1

STEP 6. VISIT THE PROJECT SITEAfter completing the preliminary layout, the en-gineer must visit the project site to view the ter-rain. Certain types of terrain can make cableinstallation and equipment placement difficult orimpractical. Examples of problems with terrainare the following:

• Sloped terrain,• Corrosive soils,• Rocky soils,• Sandy soils,• Unstable soils, or• Flood plains.

During the site visit, the engineer should lookfor these and other adverse terrain types alongthe proposed cable route and at proposedequipment locations. Ideally, the engineer willrelocate the cable or equipment to avoid theproblem terrain. Unfortunately, relocation is notalways practical, and the engineer must adaptthe design to reduce installation and mainte-nance problems. Methods for adapting a designare described under the subheadings below.This step is very important because it identi-

fies problems before construction. If these prob-lems require relocating cable or equipment, theengineer can easily modify the preliminary lay-out. Changing the location of equipment andcable during construction is very time-consum-ing and, therefore, more expensive.

Sloped TerrainInstallation of cable and equipment on slopedterrain presents a number of problems whoseseverity usually increases with the degree ofslope. Trenching across sloped terrain is difficultbecause of problems controlling the mechanizedtrenching equipment safely while achieving astable excavation whose sides are vertical.Trenching up or down sloped terrain also hascontrol and safety issues with the trenchingequipment and, additionally, introduces prob-lems with both surface erosion of the backfilland tunneling erosion around the cable or con-duit. Careful attention to tamping and com-paction, along with installing a stable groundcover, such as sod, will generally address these

problems on moderate slopes. On more severeslopes, different trenching equipment and tech-niques will need to be used, along with an an-chored or encased conduit and more aggressiveerosion control techniques.Installing pad-mounted equipment on sloped

terrain requires careful excava-tion to provide a level terracedsurface for a monolithic pador the use of a compartmentalstyle pad, even if the slope ismoderate. For more severeslopes, the use of retainingwalls of stone or timber willbe needed along with moldedor pre-cast ground sleeves of

sufficient height to span the difference in eleva-tion from the high side to the low side. Remem-ber to establish grades in such a manner thaterosion of the soil down to the transformer isminimized. Also provide for adequate level op-erating area in front of the equipment.Although it is not always possible, the under-

ground designer should try to avoid slopedareas for the installation of conductors and de-vices, or at least use the more moderate slopeswhenever practical.

Corrosive SoilsTerrain features that indicate potentially severelycorrosive soils are the following:

• Swamps,• Streams,• Poorly drained areas, or• Visible alkali (mineral salts).

These soils can corrode unprotected, buriedneutrals and ground conductors. One way toprotect neutral conductors is to prevent themfrom contacting the soil by using jacketed cable.However, the counterpoise and/or ground elec-trodes must remain in contact with the soil andbe protected by another means. For informationon corrosion protection, refer to Section 7,Cathodic Protection Requirements. That sec-tion explains how to determine if soils are cor-rosive and what types of cathodic protectionare needed.

1

Visit the project

site to identify

problem terrain.


Rocky SoilsRocky soils are often characterized by protrud-ing boulders or rocks lying on the surface. Visi-ble rock usually indicates underlying rock. Toconfirm the presence of underlying rock, the co-operative can make test borings with an anchorauger. Grading by the developer can also showsigns of underlying rock.Rock along the cable route slows installation

and increases project cost; therefore, the cooper-ative should reroute to avoid rocky areas. Ifrerouting is not practical, the cooperative willhave to use special equipment that can pene-trate rock. Because the rock is difficult to pene-trate, it may be hard to maintain the requiredburial depth. If cable cannot be placed at theminimum depth, the cooperative must providesupplemental protection such as cable place-ment in Schedule 40 PVC conduit, rigid steelconduit, or conduit encased in concrete. Thesupplemental protection must meet the require-ments of the 2007 NESC, Section 352 D.2.b. Afinal consideration in rocky soils is damage tothe underground cable, particularly the cablejacket. Rocks directly contacting the cable candamage the jacket. One way to protect the cableis to use conduit or a cable-in-conduit assembly.Either of these can be installed by trenching,plowing, or tunneling. Another option for pro-tection in a trench is to use a select backfill for acable bed and covering.

Sandy SoilsSandy soils can cause problems in at least threedifferent ways:

• Difficulty opening a trench,• Wind erosion of sand from under equipment,and

• Sandblasting of painted metal surfaces.

Sandy soils shift easily from the wind and canundermine the support of pad-mounted equip-ment. In these areas, pads with ground sleevesor basements provide better support and moresecurity than a flat pad does. They also help pre-vent exposure of cables that enter the equipment.Alternatively, the wind can blow sand and coverpad-mounted equipment, making it difficult to

access and operate. This condition is improvedby using silt fencing or shrubbery as a windblock. However, installing a wind block does in-crease the initial project cost and future mainte-nance expenses.Windy conditions in a sandy environment

provide nature’s own sandblasting machine,making it difficult to keep paint on pad-mounted equipment. After the wind-blown sandremoves the paint, the exposed metal quicklycorrodes, especially in coastal environments.One solution to this damage is to use stainlesssteel (or other noncorrosive) equipment cabi-nets. This adds substantially to initial cost, butmaintenance will be much more practical andeconomical. Another option is to use overheadprimary with underground services as the onlyunderground facilities. Placing transformers onpoles provides extra distance from the groundand may eliminate the problems caused byblowing sand.Sandy soils have little cohesion and usually

will not hold a trench open for cable placement.In addition, these soils are often in areas with ahigh water table. As a result, trenches fill withwater and are difficult to excavate. Whentrenchers are used in these conditions, they areoften equipped with a cable chute. Another ac-ceptable installation method is to use a cableplow. Increased burial depths (an additional sixto 12 inches) should be considered because cov-ering can be blown away.

Unstable SoilsSome examples of unstable soils are thefollowing:

• River banks,• Natural springs,• Unsecured embankments, and• Steep grades.

These soils shift easily and are also prone towashing. Washing can erode trenches and under-mine the support of pad-mounted equipment.Trench erosion can reduce the soil cover andpossibly expose a buried cable. Cables may alsobe exposed where soil has washed away froman equipment pad. If the washing is severe, the

1

46 – Sect ion 1

equipment could shift enough to damage trans-former bushings or cable terminations.Washing can also have the opposite effect. In-

stead of undermining pads, it can deposit largeamounts of soil around a piece of equipment.Prolonged contact with soil deposits causes themetal housing of the equipment to corrode.Such corrosion can lead to premature equip-ment failure and possible access to the interiorcompartments. The soil deposits can also blockthe equipment doors, making it difficult to main-tain the equipment.Unstable soils can also

make installation difficult. Ifgrades or embankments aretoo steep or if soils are toowet, construction personnelwill have problems maneuver-ing a trencher or a cable plow.Wet soils also tend to collapseback into the open trench, making it difficult tomaintain proper depth for cable burial.To eliminate these types of problems, the en-

gineer should avoid routing cable or placingequipment on steep slopes. If this is not practi-cal, doing the following minimizes erosion:

• Proper compaction and crowning of thetrench,

• Replanting of the slope, or• Use of equipment pads with ground sleevesor basements.

If the potential for trench erosion is severe, theengineer should consider placing the cable inconduit or installing a cable-in-conduit assemblyand possibly encasing the conduit with concrete.The engineer should also avoid placing

equipment at the bottom of steep slopes. Ifequipment must be placed in these areas, thecooperative will need to construct a water andsoil block to prevent soil accumulation aroundthe equipment.

Flood PlainsThe best way to evaluate forpossible flooding is to checktopographical maps that locateflood plains. Though most

building codes forbid the placement of struc-tures in flood plains, these areas can usually betraversed with cable. Flooding has little effect onburied cable and should present problems onlyif the cable fails while the cable route is flooded.If the cable section is part of an open-loop sys-tem, the flooded section can be isolated. How-ever, if the cable section is part of a radialsystem, the engineer should consider providingan alternative feed.The cooperative may have to place equip-

ment in areas subject to flood-ing. Dead-front, pad-mountedtransformers and dead-front,oil-insulated switching cabi-nets can operate during occa-sional immersion. However,these devices must be sup-ported by pads that will notfloat. Otherwise, the device

may be displaced, possibly causing a systemoutage or exposing the interior compartments.Air-insulated switching cabinets will fail if sub-merged in water and, therefore, must not beused in areas subject to flooding.

STEP 7. OBTAIN ALL EASEMENTSThe cooperative must get an easement fromall affected property owners before installingany underground facilities. By definition, aneasement is a right afforded a person to makelimited use of another’s real property. This ease-ment gives the utility the legal right to enter theproperty and access a right-of-way strip. Forunderground facilities, this right-of-way mustbe a minimum of 10 feet wide—five feet oneach side of the centerline of the electrical facili-ties. The 10-foot width provides enough spaceto operate a trencher or other piece of installa-tion equipment. The easement must define thewidth and boundaries of this right-of-way strip.These rights-of-way should also be shown and

recorded on the plat.To reduce misunderstand-

ings between the cooperativeand its property owner mem-bers, the easement must bespecific in defining the coop-erative’s rights. As a minimum,

1

Unstable soils

can make

installation difficult.

Get an easement

before installing any

underground facilities.


1Project No. ________________________

Drawn by ___________________________

STATE OF ______________________________COUNTY OF ____________________________

KNOW ALL MEN BY THESE PRESENTS, that __________________________________________________,_________________________________________________________________________________________hereinafter called “Grantor” (whether one or more), in consideration of the sum of One Dollar ($1.00) andother good and valuable considerations, does hereby grant unto__________________________________,its successors, and assigns, hereinafter called “Grantee,” the right, privilege, and easement to go in andupon that certain land of Grantor (hereinafter “premises”) situated in said County and State, bounded bylands of:_____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

and over and across said premises within a right-of-way strip having a width of _____ feet on each sideof a centerline determined by the centerline of the electrical facilities as installed, to construct, maintain,and operate underground lines and conduits with other necessary apparatus and appliances, either aboveground or below ground, to include transformers and service connections, for the purpose of transport-ing electricity and for the communications purposes of Grantee and its licensees. The following rights arealso granted to Grantee: to enter said premises to inspect said lines, to perform necessary maintenance andrepairs, and to make alterations and additions thereto; and to clear the land within the right-of-way stripand to keep it clear of trees, structures, or other obstructions; and to clear that land outside the right-of-way strip and to keep the area within 10 feet of said door clear of trees, structures, or other obstructions.All underground facilities are to be installed in accordance with the provisions of Grantee’s UndergroundDistribution Installment Plan, __________________________________, receipt of a copy of which is ac-knowledged by Grantor.

This right-of-way is given to permit the construction of electrical facilities presently proposed. Facilities atother locations and future extensions of presently constructed facilities are not permitted by this agreement.The foregoing notwithstanding, Grantee may relocate its electrical facilities and right-of-way strip over thepremises to conform to any future highway or street relocation, widening, or improvement.

IN WITNESS WHEREOF, the Grantor has hereunto set his hand and seal, or, if corporate, has caused thisinstrument to be signed in its corporate name by its fully authorized officers and its seal to be hereuntoaffixed by authority of its Board of Directors, this _______ day of __________________, 20___.

Witness________________________________________________________________________(SEAL)

________________________________________(SEAL)________________________________________(SEAL)________________________________________(SEAL)______________________________________________

(Corporate Name)ATTEST:____________________________________ By_________________________________________

_________ Secretary _________ (President)

Sample Easement

FIGURE 1.28: Sample Easement.

48 – Sect ion 1

the cooperative must have the right to install,operate, maintain, and replace the electrical fa-cilities located within the right-of-way strip.These activities require the right-of-way to beclear of trees, structures, and other obstructions.Rights-of-way that were clear during the installa-tion of underground facilities will likely becomeobstructed as property owners erect fences, stor-age buildings, and landscaping. Because theseobstructions must be cleared to repair or replacethe underground facilities, the easement mustspecifically define the cooperative’s right to clearthe right-of-way.Another area of conflict is clear space in front

of the doors of transformers and sectionalizingcabinets. As noted, maintenance of these devicesrequires a clear working space 10 feet out fromthe door (see Figure 1.27). The consumer mayconsider these devices unattractive and try tohide them with landscaping or a surroundingstructure. As a result, the cooperative cannotmaintain the device. These conflicts are more eas-ily resolved if the easement states that the areawithin 10 feet of the door of any transformer orcabinet will be kept clear of any obstructions.Because the easement is a legal document, it

must be filled out completely and correctly, in-cluding getting the signatures of all propertyowner members of a particular tract or the sig-natures of appropriate corporate officers, ifowned by a corporation. The easement must benotarized and filed with the appropriate munici-pal, parish, or county authority in which the prop-erty lies. Figure 1.28 shows a sample easement.Obtaining and recording an easement can be

time-consuming, particularly if one undergroundproject involves multiple property owners, thusrequiring multiple easements. To avoid thisproblem in a subdivision, the cooperative iswise to get one easement from the developerbefore any lots are sold. This way, the coopera-tive needs only one easement for all theplanned underground facilities in the subdivi-sion. The cooperative will also benefit if the fol-lowing occur:

• The right-of-way strip is shown and recordedon the plat.

• The subdivision restrictions define thecooperative easement as transferable tonew owners.

STEP 8. Prepare Staking SheetsThe final step is preparing a staking sheet. Forsmaller projects, the staking sheet providesenough space for a sketch of the required work.Figure 1.29 shows a staking sheet for under-ground service to a commercial consumer.For larger projects, the engineer will have to

attach a separate construction drawing. For sub-division installations, the engineer can show therequired work on a subdivision plat. This con-struction drawing should show the trench,equipment, and street lighting locations andnote any conduit or temporary pedestal installa-tions. The construction drawing could also havedetails showing how far to offset equipmentfrom the property line and the location of otherunderground utilities.Underground staking sheets provide impor-

tant project information to several departmentswithin the cooperative. These departments mustbe able to easily interpret the staking sheet. Thestaking sheet is used to generate a materials list.Purchasing and materials personnel use this listto order and stock the necessary materials.Scheduling personnel will use the staking sheetto estimate the manpower and equipmentneeded to construct the project. Staking person-nel use the sheets to physically mark the fieldlocations of equipment and trenches. While inthe field, staking personnel may have to adjustthe layout for conflicts with other utilities or forterrain problems. Any changes made in the fieldmust be shown on the staking sheet.After personnel have staked the project, con-

struction crews will use the staking sheets for in-formation on installing the underground facilities.If the construction crews modify the layout, theymust also modify the staking sheet. The stakingsheet must agree with the as-built project be-cause these sheets are the basis for the coopera-tive’s mapping system. Accurate staking sheetsproduce accurate system operating maps and ac-curate permanent plant and accounting records.

1

DesignofanUndergroundDistributionSystem

–49 1

FIGURE

1.29:StakingSheetforServicetoaCommercialConsum

er.Source:PiedmontElectricMem

bershipCorporation,Hillsborough,N.C.

HWY86SOUTH

50 – Sect ion 1

1. Equipment mountings provide support forpad-mounted equipment. Flat pads aresometimes suitable for single-phase pad-mounted transformers and small single-phase fuse cabinets.

2. Cable wells used with a flat pad providemore space for cable training and are suit-able for three-phase pad-mounted transform-ers and junction cabinets.

3. A box pad is useful to support pad-mountedswitchgear and for installations on slopes orhillsides.

4. The main types of underground systems arethe following:

• circuit exits,• main feeders,• sub feeders,• transformer and secondary systems, and• street and area lighting.

5. In designing a UD system, safety, reliability,cable ampacity, equipment ratings, voltagedrop, and voltage flicker must be considered.

6. Placing facilities along the front property linemakes them more accessible for operationand maintenance.

7. A joint-use trench often creates operatingproblems. To minimize these problems, the

location of a joint-use trench must beshown on all operating maps.

8. Joint-use trench with other utilities re-quires a contractual arrangement amonginvolved parties.

9. System upgrades should be planned byconsidering future voltage conversions,three-phase cable installation, and con-duit installations.

10. The UD design can be improved by com-paring the economics of different systemconfigurations.

11. The UD system should be designed tominimize cable and pad-mounted trans-former losses.

12. The steps for layout of a UD system areas follows:

STEP 1: Get the required information.STEP 2: Arrange the service and trans-

former layout.STEP 3: Calculate the consumer load and

select proper equipment ratings.STEP 4: Select the primary cable route.STEP 5: Locate sectionalizing equipment.STEP 6: Visit the project site.STEP 7: Obtain all easements.STEP 8: Prepare staking sheets.

1Summary andRecommendations

Cable Select ion – 51

Cable Selection2

Typical CableConfiguration

In This Section:

The heart of any underground system is thecable that carries power from the source to theload. The cable must incorporate the most im-portant characteristics of the ideal utility system:low initial cost and high reliability. Experiencewith early UD cables has forcefully shown thatthe lowest-cost cable that can be successfullyplaced into operation is not necessarily the bestchoice. It is necessary to pay close attention tothe design and manufacture of all cables.This section provides an introduction to the

technical aspects of electric distribution cables.

It addresses the designs and materials most ef-fective in delivering reliable and economicalservice. The variety of cable features availablefor the various applications is also addressed.Recommendations are included for conditionsgenerally encountered on rural electric systems.The main components of cables reviewed in-clude the conductor and the insulation system(including shielding). The concentric neutraland jacket options for primary voltage cablesare also covered.

Typical Cable Configuration

Conductor Size Designations

Conductor Materials and Configuration

Cable Insulation Materials

Insulation Fabrication

Conductor Shields andInsulation Shields

Cable Specification and Purchasing

Cable Acceptance


The main types of cables used on rural electricsystems are primary voltage (15- to 35-kV class)shielded cables and secondary voltage (600-voltclass) unshielded cables. The higher voltage ca-bles are used on systems rated 7.2/12.5 kV, 14.4/24.9 kV, and 19.9/34.5 kV. Such cables are classedby the phase-to-phase voltage of the system onwhich they are intended to operate. For instance,cable designed for application on a 7.2/12.5-kVsystem will be rated 15 kV, regardless of whetherit is in a single-phase or a three-phase circuit.

To gain an overview of cable design, the en-gineer should consider the components of thesystem. The focus should be on single-conduc-tor cable because it is the predominant type ofcable used in rural and suburban distribution sys-tems in North America. Typical system voltagesare 7.2/12.5-kV, 14.4/24.9-kV, and 19.9/34.5-kVgrounded wye.Most of the cables on these systems are of

concentric neutral design. Generally, the majorcable components are the following:

52 – Sect ion 2

• Conductor,• Conductor shield,• Insulation,• Insulation shield,• Concentric neutral, and• Jacket.

These are illustrated in Figure 2.1.Figure 2.1 represents a typical primary cable

used in underground distribution and is the con-figuration currently recommended. Variations ofthis design may be better suited to particulartypes of installations.Figure 2.2 shows the arrangement of an under-

ground cable design widely used from the mid-1960s to the late 1980s. It is identical in most re-spects to the cable in Figure 2.1, except that itdoes not have a jacket over the concentric neu-tral. It was most often installed as a direct-buriedcable, and exposure of the concentric neutral tothe surrounding earth provided an excellent sys-tem ground. However, this cable design fell intodisfavor because of substantial corrosion problemsaffecting the concentric neutral. Loss of the neu-tral wires led to an open neutral circuit, posingserious operational, reliability, and public safety

problems. In addition, loss of neutral conductorscaused deterioration of the semiconducting insu-lation shield and consequent cable failure. Useof bare concentric neutral cable is not approvedby RUS for use on the systems of its borrowersand has essentially been discontinued except incases where there are no corrosive conditionsand special permission has been obtained.Another special case of the medium-voltage,

single-conductor cable is illustrated in Figure 2.3.The main difference from the cable in Figure 2.1is that the concentric neutral is replaced by alongitudinal corrugated (L.C.) shield or a coppertape shield. A separate neutral conductor thusmust be installed with a circuit to handle returncurrents. The purpose of the L.C. shield or tapeshield is to provide a path for capacitive currentsand, thus, ensure an even voltage gradient withinthe cable. The major advantage of this configura-tion is in circuits where loads are relatively high(≥ 300 amperes). See Section 4 for more infor-mation on sheath currents and cable ampacity.The following subsections, which describe in-

dividual components of underground cables inmore detail, provide an understanding of desir-able features for various applications.

2

Conductor

Extruded Conductor Shield

Insulation

Extruded Insulation Shield

EncapsulatedNeutral Conductors

Jacket

Conductor


Insulation


Metallic Tape Shield

Jacket

Conductor


Insulation


Bare Neutral Conductors

FIGURE 2.1: Jacketed ConcentricNeutral Cable. Source: OkoniteCompany, 2006.

FIGURE 2.2: Bare Concentric NeutralCable. (Not RUS accepted.)Source: Okonite Company, 2006.

FIGURE 2.3: Medium-Voltage PowerCable with Tape Shield and L.C.Shield. Source: Okonite Company.


U.S. standards use two systems for designatingconductor size. The oldest of these is the AWG,which was formerly known as the Brown andSharpe wire gauge. This system is typically usedon conductors up through those with a diameter

2Conductor SizeDesignations

Equation 2.1

A = πr2

where: A = Area in square inchesπ = 3.1416r = Radius (in inches)

For Area in kcmil, use Radius in 1/1,000 inch.

of 0.460 inch (4/0 AWG). The second system isthe circular mil designation, which is alwaysused on conductors larger than 4/0 AWG. How-ever, circular mil designations may also be ap-plied to conductors of 4/0 AWG and smaller.The AWG originated in the mid-19th century.

Each step in this gauge approximates the succes-sive steps in the wire drawing process. Empiricalhistory sets the two endpoints: 4/0 AWG, with adiameter of 0.460 inch, and No. 36 AWG, with adiameter of 0.0050 inch. There are 39 equally di-vided steps between these two sizes. A few ap-proximate relationships may be useful:

• Each increase of three-gauge numbersdoubles the area and the unit weight, andalso halves the dc resistance.

• Each increase of six gauge numbers doublesthe diameter.

• Each increase of 10 gauge numbers multipliesthe area and unit weight by 10, and alsodivides the dc resistance by 10.

The circular mil system is based on the defini-tion of a circular mil (cmil) as being the area ofa wire with a diameter of one mil (0.001 inch).Area is calculated as shown in Equation 2.1.One cmil is (0.0005)2 π or 7.854 × 10-7 inch2.

It follows that 1,000 circular mils or 1.0 kcmil(formerly MCM) is equal to 7.854 × 10-4 inch2 insolid wire. Therefore, a 4/0 AWG wire, whichhas a diameter of 0.460 inch, has a circular milequivalency of 211,600 cm and an area of0.1662 inch2.The AWG and circular mil systems are now lim-

ited to U.S. and Canadian use. European designa-tions are based on metric units of square millime-ters (mm2). Table 2.1 shows AWG, circular mil,and metric designations for common conductorsizes used in North American distribution cables.

AreaAWG kcmil

mm2 in.2Diameter (in.)

6* 26.24 13.3 0.0206 0.162

2* 66.36 33.6 0.0521 0.258

1/0* 105.60 53.5 0.0829 0.325

2/0* 133.10 67.4 0.1045 0.365

4/0* 211.60 107.0 0.1662 0.460

— 250.00** 127.0 0.1967 0.575

— 350.00** 177.0 0.2749 0.681

— 500.00** 253.0 0.3927 0.813

— 750.00** 380.0 0.5891 0.998

— 1,000.00** 507.0 0.7854 1.152

* Solid** Stranded

TABLE 2.1: Dimensional Characteristics of Common Conductors(Standard Concentric-Lay).

ConductorMaterials andConfiguration

MATERIALSSince the first cable system, only two conductormaterials have played a significant role: copperand aluminum. These materials have appearedin a variety of alloys, tempers, and configura-tions. In the late 1960s, some utilities briefly ex-perimented with sodium as a conductor

material; however, it was not cost-effective be-cause of the special precautions required duringinstallation and maintenance.Copper was the first material to play a major

role in cable construction. With a volume resistiv-ity of 1.673 × 10-7 ohm-meters (ohm-m) in its pure(99.999 percent) state, it compared favorably with

54 – Sect ion 2

other metals. Supplies were abundant and itcould be economically fabricated. Connectionswere simple to make and corrosion resistancewas good. However, with the rapid developmentof the aluminum industry in the first half of the20th century, aluminum became cost-effective forapplications in which physical size was not critical.To take advantage of this economic benefit, theelectric industry developed methods to overcomesome of the other physical disadvantages of alu-minum. These disadvantages included higher sus-ceptibility to flexural fatigue, the high resistivityof natural surface oxides, and cold flow (creep).For economic reasons, cables now used on

underground systems are predominantly alu-minum. The use of this metal leads to a largercross-sectional area and, consequently, greateroverall cable dimensions, but, in most cases, theadditional cost of other project components—such as larger size conduit—does not outweighthe present economic advantage of aluminumconductors. Aluminum conductors have a volumeresistivity of 2.655 × 10-7 ohm-m. Comparing thisresistivity with the previously mentioned coppervolume resistivity shows that, for equal cross-sectional areas, aluminum will have 1.59 timesthe resistance of the same-size copper conductor.To simplify the comparison of various con-

ductors, the industry uses a measure of relativeconductivity that compares a particular metal toannealed electrolytic copper. This measure is re-ferred to as the International Annealed CopperStandard (IACS). The volume resistivity of an-nealed copper is defined as 1.724 × 10-7 ohm-mat a temperature of 20°C (68°F).As the tensile strength of materials increases,

the conductivity decreases. As an example, hard-drawn copper has experienced an increase in

tensile strength because of work hardening dur-ing the drawing process and its conductivity hasfallen to 97.2 percent IACS. By comparison,1350H19 aluminum has a conductivity of about61 percent IACS. The lower conductivity is mainlycaused by the inherently higher volume resistivityof pure annealed aluminum. See Table 2.2 for acomparison of common conductor materials.Because thermal capacity of conductors and

cables is a function of the heat generated by in-ternal conductor losses, the ampacity of thehigher conductivity copper conductors of equalsize is approximately 1.6 times that of matchingaluminum conductors. Of course, other signifi-cant elements determine the exact cable ampac-ity. These are discussed more extensively inSection 4 of this manual.

CONDUCTOR TEMPERBoth copper and aluminum conductors areavailable in various tempers that designate therelative hardness of the metal. Whereas over-head conductors have generally used hardermetal to increase tensile strength and reducesags, underground conductors have tended touse the lower tempers, because high tensilestrength was not usually required. Most copperpower cables have used soft-drawn copper forits greater flexibility. This flexibility not onlymakes fabrication easier but also improves in-stallation handling, especially for larger cables.Where high tensile strength is needed for cablepulling, special installations might use hardertempers. However, this would only be wherehigh unit stresses would be imposed on thecable conductor during installation or perhapsduring cable life. Examples include mineshaftriser cables or cables for extremely long pulling

2Copper Aluminum

Medium 1/2 Hard 3/4 Hard Hard DrawnSoft Drawn Drawn Hard Drawn (H14/H24) (H16/H26) (H19)

Rated Tensile Strength — 42–60 ksi 49–67 ksi 15.0–20.0 ksi 17.0–22.0 ksi 24.5–29.0 ksi

Conductivity (% IACS) 100 96.7–97.7 97.2 61.0 61.0 61.0

Note. ksi = thousands of pounds per square inch

TABLE 2.2: Conductor Physical and Electrical Characteristics.


distances in duct. Such cables would require cus-tomized design for their particular circumstancesand are beyond the scope of this manual.Aluminum conductors in power cables are

generally furnished in the 3/4-hard temper. Thisprovides a reasonable level of tensile strength,while not introducing excessive ductility thatwould lead to creep problems in making durableconnections. As the conductor cross section in-creases to 750 kcmil or greater, there is some ac-ceptance of aluminum conductors in the 1/2-hardtemper. This gives adequate tensile strengthwhile maintaining a higher degree of flexibility.All characteristics of aluminum conductors, es-pecially tensile strength, must be consideredwhen specifying a cable. The specifying engi-neer must consider the mechanical stresses onthe cable during installation and service.More information on conductor characteristics

can be found in reference books. Nationally ac-cepted specifications for electrical conductorsare found in American Society for Testing andMaterials (ASTM) standards. Copper wire is cov-ered by ASTM Specifications B-1, B-2, and B-3.Aluminum wire is covered by ASTM SpecificationB-230. Methods for measuring the most impor-tant characteristics of these and other materialscan be found in other related ASTM standards.Aluminum conductors used in undergroundcable are addressed in other ASTM standards, in-cluding B-231 (concentric lay conductors) andB-400 (compact round conductors).

CONDUCTOR ALLOYAluminum conductor material also is designatedby an alloy number. The alloy designation derivesfrom the description of aluminum alloys in otherapplications in which such characteristics as hightensile strength are required. However, becausehigh electrical conductivity (low resistivity) is thesingle most important aspect of underground ca-ble conductors, pure aluminum is generallyused. The alloy designation for electrical alumin-um is EC. It was formerly designated as Alloy1350. The same aluminum nomenclature systemincludes designations for temper. These are alsoshown in Table 2.2. For example, 3/4-hard tem-per has a classification of H16 or H26. The dif-ference between H16 and H26 tempers is that

2the H16 alloy is only strain-hardened. The H26alloy has the same general characteristics, but ithas been partially annealed after strain hardening.Copper conductors are almost universally sup-

plied as pure copper. Pure copper provides thehighest conductivity and, therefore, the highestefficiency. Because pure copper in its varioustempers provides adequate mechanical strengthfor cable applications, there is generally no needfor alloyed copper conductors.

CONDUCTOR CONFIGURATIONThe wire and cable industry offers the electricutility industry a wide variety of standard con-ductor configurations, including solid conductor,various stranding arrangements, and filled-strandconductors. Each configuration has its own ad-vantages. The engineer selecting a cable designmust consider these alternatives and select theoption that produces the best cable for the par-ticular application. Elements significantly af-fected by the conductor configuration includethe following:

• Flexibility during installation (cable bendingand racking),

• Flexibility during operations (elbow switch-ing), and

• Longitudinal water migration.

Though the decision on conductor configura-tion alone will not provide the solution to any ofthese problem areas, it is a vital part of thelarger process of selecting a cable that will pro-vide high reliability and economy.The simplest configuration is the solid, single-

strand conductor. Solid conductor is preferred insmaller cable sizes because of its absolute water-blocking capability. Because there are no voidsto fill, there will be no continuing migration ofwater through the insulation system. Perhapsmore important, if moisture does penetrate theinsulation, it cannot migrate along the cable con-ductor to other areas of the cable. The inhibitionof moisture migration is extremely important inreducing insulation deterioration problems soprevalent in underground cables.As is well known, the stiffness of cable in-

creases as conductor diameter increases. Cable

56 – Sect ion 2

stiffness will increase in pro-portion to the square of the di-ameter of the solid conductor.Therefore, a point will bereached at which the cablewill become unmanageable,especially where bending inconfined spaces is required to

2operate load-break connec-tors. The solution is the use ofstranded conductors. Thesmaller diameter of the indi-vidual strands lowers the totalforce required to achieve thenecessary bending. The rea-sonable upper limit for solid

conductors with 3/4-hard aluminum conductorshas generally been found to be 2/0 AWG. Abovethat size, stranded conductors are advised.Several options in stranded conductors are

available, including conventional concentric lay,compressed strand, and compact configurations.Some of these are illustrated in Figure 2.4.The simplest stranded configuration is the

conventional concentric round stranding thatuses multiple layers of circular wires. Each layerof wires is laid in the opposite direction. Thepredominant combinations for conventionalstranded cable are 1 + 6 = 7, 1 + 6 + 12 = 19,and 1 + 6 + 12 + 18 = 37. These are illustrated inFigure 2.5.The first option, concentric round stranding,

obviously produces interstices (voids) betweenthe surfaces of the individual wires. These inter-stices have two important effects. First, for agiven equivalent metallic cross section of con-ductor, the outside diameter of a stranded cablewill be greater than for an equivalent solid con-ductor. Second, the voids are continuous alongthe cable and provide an excellent path formoisture migration. In conventional stranding,the conductor metal will occupy only 76 to 78percent of the area enclosed by a circle drawnaround the outside of the conductor.The number of wires in a concentric stranded

conductor is defined in ASTM standards as theclass of the conductor. Details are contained inASTM Standards B8 (copper) and B231 (alu-minum). An examination shows that the im-proved flexibility of higher stranding comes atthe expense of larger diameter. In addition, thestranded conductors weigh more because theouter layers must be longer than the conductoraxis. Table 2.3 compares the various strandingcharacteristics of a common single size of alu-minum conductor.

Concentric Stranded Conductor, 37-Wire

Compressed-Strand Concentric Conductor, 37-Wire

Compact Concentric-Strand Conductor, 37-Wire

Use solid or strand-

filled conductors

for reliability.

FIGURE 2.4: Concentric Lay Strand Options.

FIGURE 2.5: Standard Strand Arrangements for Multilayer Conductors.

1 6 12 18 24 30 36 42Number of Wires Per Layer


The second stranding option, compressedstrand, is an improvement on the conventionalstrand arrangement. This configuration is accom-plished by drawing the completed conventionalconcentric round strand to compress the outerlayer of strands after fabrication (see Figure 2.4).The result is some reduction in diameter andsome reduction in the interstices of the outerstrand layer. This configuration also gives asmoother, more nearly cylindrical surface. Incompressed strand, the conductor metal will oc-cupy 81 percent to 83 percent of the area of acircle that encompasses the overall diameter.Compressed strand reduces the diameter be-tween one-half and three percent. One disad-vantage is some loss of flexibility because theoutside layer is slightly more rigid.The third conductor type (see Figure 2.4) is the

compact round design. With this design, the con-ductor is drawn after each layer is applied, whichgreatly reduces the interstices on each layer andbrings the metallic cross section up to 92 to 94percent. The cable diameter is reduced by aboutnine percent when compared with the same cross-sectional area in a concentric round configuration.

FILLED-STRAND (SEALANT) CONDUCTORAs noted in the previous subsections on conduc-tor configurations, the useful service life of un-derground cables has been reduced by moisturein the insulation system. This has been particu-larly true where moisture has been present inthe conductor interstices and, thus, had accessto the conductor/conductor shield interface.Therefore, it is important to stop the migrationof any moisture that may find its way into theconductor.Impeding moisture migration is most econom-

ically accomplished by the addition of a strand-filling material during manufacture to fill allvoids within the conductor. The material mustbe compatible with the conductor and the semi-conducting strand (conductor) shield. Often, thisrequirement means the strand filler will be es-sentially the same as the strand shield except forplasticizers added to improve viscosity. Thestrand filler is often applied to each of the innerlayers during the stranding process. If this ap-proach is used with proper controls, the inter-stices should be filled while the outside of theconductor is left clean.

2Stranding Individual Wire Overall Diameter Weight DC ResistanceClass Number of Wires Diameter (in.) (in.) lb./1,000 ft ΩΩ/mile @ 20°C

Solid 1 0.4600 0.460 194.7 0.4228

A, AA 7 0.1739 0.522 198.7 0.4311

B 19 0.1055 0.528 198.5 0.4311

C 37 0.0756 0.529 198.5 0.4311

D 61 0.0589 0.530 198.7 0.4311

TABLE 2.3: Configurations of 4/0 AWG Aluminum Conductor.

Cable Insulation Materials

OVERVIEW OF CABLE INSULATION MATERIALSEarly cable insulation materials were mainly nat-ural rubber compounds. Paper insulation wasintroduced for power cables about 1890. Butylrubber was introduced in 1944 for distributioncable systems.The trend toward placing electric distribution

lines underground was significantly aided in the1960s by the wide acceptance in the United States

of high-molecular-weight polyethylene-insulatedcables. Cables constructed of HMWPE were in-troduced in 1948. These had several advantagesover the butyl rubber primary voltage cablespredominant in industrial applications. In theearly 1960s, EPR (ethylene propylene rubber) in-sulated cables became available for distributionsystems. However, the industry considered EPRcables to be premium-priced cables and they

58 – Sect ion 2

did not gain wide acceptance, especially in theunderground distribution market where initialcost was the governing factor before the impor-tance of long cable life was recognized.About 1963, cross-linked polyethylene (XLPE)

cables became available for distribution installa-tions in both concentric neutral and conven-tional power configurations. The initialadvantage of XLPE cable was that, like EPR, it isa thermosetting material with a higher allowableoperating temperature. It was 1975 before XLPEcable equaled HMWPE cable in market share fordomestic utilities. HMWPE cable continued to bepopular because of its better technical character-istics and lower cost. HMWPE possessed a lowdielectric constant, along with high dielectricstrength and very good insulation resistance. Italso cost less than XLPE. In 1966, some utilitiesreported failures of HMWPE-insulated cables.The failure rate was about one per 1,000 mile-years. By 1970, the reported HMWPE failure ratehad reached about two per 1,000 mile-years andwas considered to be a significant problem.Soon thereafter, the failure rate for HMWPE ca-bles rapidly escalated and reached almost eightper 1,000 mile-years by 1982. Recognition ofpremature insulation breakdown in HMWPE ca-bles contributed to the rapidly increasing accep-tance of XLPE as an insulating material. About1975, the reported failure rate of XLPE cablesreached one per 1,000 mile-years. In about 1980,the failure rate of XLPE cables rapidly escalated,just as HMWPE insulation did earlier.Because of concerns with the failure of

HMWPE and XLPE insulations to deliver the ex-pected design life, cable insulation manufactur-ers began searching for methods to improve thelife of the product. The initial major develop-ment was tree-retardant polyethylene (TR-PE)compounds, so named because it resisted thegrowth of electrochemical“trees” which led to insulationfailure. These have been intro-duced in both high-molecular-weight polyethylene(TR-HMWPE or TR-PE) andcross-linked polyethylene (TR-XLPE). These compoundshave exhibited a substantial

improvement in cable life expectancy as pre-dicted by accelerated testing methods. TR-XLPEproved to generally be the superior compoundand gained much wider acceptance than did TR-HMWPE. In fact, TR-HMWPE is no longermanufactured. The tree-retardant characteristicof the initial TR-XLPE compound was acquiredby adding organic compounds to the basic poly-ethylene material.As a result of escalating polyethylene cable

failure rates, EPR cables have seen wider accep-tance in UD installations. Since the 1960s, thesecables have also enjoyed technical improve-ments in insulation compounds and fabricationtechniques. History and accelerated life testshave shown EPR to be equal or superior to con-temporary TR-XLPE compounds. Without ques-tion, insulating compounds will continue toimprove. Continuing tests will evaluate thelongevity of different cable compounds andcable fabrication methods. Cooperative engi-neers must use all available information whenselecting a cable for purchase.One hundred percent insulation wall thick-

nesses are 175 mils (4.4 mm) for 15 kV, 260 mils(6.6 mm) for 25 kV, and 345 mils (8.8 mm) for35 kV. These insulation wall thicknesses arespecified by the ANSI/ICEA and are referred toas the 100 percent level. Many cable users spec-ify an increased wall thickness, as discussedbelow, and use this minimum 100 percent insu-lation wall thickness only for upgrading or retro-fitting projects in which duct sizes are restrictedand conduit fill may be exceeded.Polymer insulation thicknesses are often in-

creased to 133 percent or 173 percent of the val-ues listed above. The choice of insulationthickness depends on the system connection (ei-ther delta or wye connected), the system protec-tion available, and the desire for longer cable

life. Standards state that the100 percent insulation level issatisfactory for any systemwhere faults can be clearedwithin one minute, which ap-plies to most installations ongrounded systems. For delta-connected or ungrounded sys-tems, 133 percent insulation

2

Review the results of

accelerated cable life

tests when selecting

cable insulation.


thickness is commonly chosen. In addition, the133 percent insulation level is recommended bystandards where fault-clearing times on wye-connected systems are in excess of one minutebut less than one hour. The additional insulationthickness will also reduce the electrical stresswithin the insulation and, hence, prolong cablelife, which many utilities find advantageous.One disadvantage of an increase in insulationthickness is that the additional insulation volumeincreases the opportunity for contamination.However, this is not a realistic concern for mod-ern cable manufacturing facilities. Also, the addi-tional insulation, shield, and jacket materialsneeded because of the increased diameter willincrease the final installed cable cost. This is dueto the increased cost of the cable, the increasedpulling and training effort, and the increase induct size required. Finally, 173 percent insula-tion is used for cables on a system, usually deltaor resistance-grounded, which may have a clear-ing time of more than one hour.It should be noted that the performance of

175-mil direct buried distribution cables on 12.5/7.2 kV systems proved unsatisfactory in earlyunderground systems. This was due to treeing ofthe insulation which could in part, be attributed tothe higher voltage stresses present in the 175-milinsulation. This was particularly true in smaller(e.g., #2 AWG) conductor sizes. For this reason,RUS mandates the use of 133 percent insulationthickness (220 mil) for 15 kV class cables.RUS is currently refining its Specifications for

Underground Primary Cables in Bulletin No.1728F-U1, which updates and supersedes formerBulletin 50-70 (U1), dated December 22, 1987.In this new bulletin, RUS adopted the insulationthickness shown in Table 2.4 and these will bespecified in the pending bulletin.

2

Voltage Insulation Thickness Class (kV) Thickness (mils) Level (%)

15 220 133

25 260 100

35 345 100

TABLE 2.4: RUS Insulation Thickness.

INSULATION MATERIAL CHARACTERISTICSAn individual selecting a particular cable insula-tion should be familiar with the basic physicaland electrical characteristics of various materials.Each of these characteristics affects the suitabilityof an insulation material for a particular applica-tion. Selecting a cable construction involvescompromise as most materials have differentstrong and weak points.Physical characteristics of the insulating layer

affect the resistance of a cable to mechanicaldamage under normal operating conditions. Situ-ations imposing mechanical stresses on cable in-clude the following:

• Soil pressure in direct-burial installations,• Sidewall pressure on cables pulled into con-duit,

• Flexure during switching operations forelbow-connected apparatus,

• Expansion/contraction in ducts, and• External clamping action on risers.

Some of the pertinent physical properties arelisted below.

Hot CreepThis is a measure of the plasticity of a material atelevated temperatures. It shows the ability of aninsulating material to resist deformation at elevat-ed operating temperatures. For thermosetting in-sulations, the hot creep is generally measured at130°C (266°F), which is the maximum emergencyoperating temperature. The hot creep is deter-mined by measuring the tensile stress (poundsper square inch, or psi) needed to stretch the in-sulation sample to 200 percent of its originallength. See Figure 2.6 for a relative comparisonof the hot creep of HMWPE (thermoplastic),XLPE (thermosetting), and EPR (thermosetting).

High-Temperature Aging CharacteristicsElectrical insulation in power cables must retaingood physical properties after being subjected tohigh temperatures. High-temperature aging evalu-ations usually compare tensile strength and elon-gation remaining after seven days (168 hours) ofexposure to temperatures ranging from 120°C to180°C (248°F to 356°F).

60 – Sect ion 2

ELECTRICAL CHARACTERISTICS OF INSULATION MATERIALSThe electrical characteristics of cable insulationare just as important as the physical characteris-tics. After all, if a cable is mechanically durablebut will not withstand the applied voltage, thecable no longer serves its intended purpose.Electrical characteristics include insulation resis-tance, insulation power factor, and dielectricconstant. Basic electrical characteristics of cableinsulation are discussed extensively in Section 4,Equipment Loading.

2

FIGURE 2.6: Comparative Hot Creep vs.Temperatures for Cable Insulation Materials.Adapted from ANSI/ICEA T-28-562.

100% Hot Modulus

Temperature (°C)20 75 90 130 250

EP

XLPE

HMWPE

Insulation Fabrication

All contemporary cables use extruded dielectricinsulation. The manufacturing processes gener-ally are similar for different insulation materialsand different voltage classes. The most complexmanufacturer’s process involves primary voltagecables that have not only extruded insulationbut also extruded conductor shields and extrudedinsulation shields. Secondary cables have similarconstruction methods, but employ only an insu-lating layer or, in the case of “ruggedized” styles,possibly two layers.Many aspects of the manufacturing process are

very important. Some of these are the following:

• Purity of the insulation material,• Lack of voids in the insulation and shields,• Smoothness of the conductor shield and conductor,

• Adhesion between the conductor shield andthe insulation,

• Cleanliness of the conductor shield-insulationinterface,

• Smoothness of the insulation outer surface,• Adhesion between the insulation and theinsulation shield,

• Cleanliness of the insulation–insulation shieldinterface,

• Maintenance of uniform dimensions and con-centricity along the cable, and

• Inclusion of agglomerates, gels, and ambers.

Failure to adhere to any of these requirementsat any point in the manufacturing process willlead to defective cable that is unsuitable for util-ity applications.

MATERIAL HANDLINGOne of the most important requirements ofcable manufacturing is cleanliness of the rawmaterials. The cable manufacturer receives insu-lating and shielding materials, particularly poly-ethylene compounds, as pellets. These pelletsmust be handled very carefully at both the cableplant and at the insulation manufacturing plantto ensure there is no contamination. Qualitycontrol tests that meet, or exceed, industry stan-dards must be made on each batch of pellets toensure cleanliness. In addition to normal qualitycontrol sampling, some plants use optical scan-ning to continuously sample pellets before theyenter extruding equipment. This sampling isbeneficial because contaminated pellets are re-jected before being extruded into the cable.Resin suppliers now employ online pellet in-

spection devices. Some manufacturers inspect100 percent of their product. From this, a newgeneration of XLPE and TR-XLPE materials thatbear designations of extra clean, ultra clean, or


super clean has emerged. However, a precisedefinition of each designation based on per-unitvolume contamination is not available, nor is acomparison between compound manufacturers.The opaque nature of EPR does not permit asimilar determination of cleanliness.Cable manufacturers, in turn, have implemented

materials-handling systems to prevent contamina-tion during the course of manufacture. For ex-ample, Class 1000 clean rooms have been in-stalled in most cable manufacturing plants andseparate handling facilities for insulation andsemiconductor materials have been implemented.Supersmooth semiconducting shields were

first introduced in 1988, resulting from betterdispersion of the acetylene carbon black in thepolymer base. Better dispersed semiconductingshields provide for a much smoother interfacebetween the insulation and the shields, leadingto much longer service life. Utility acceptance ofthe cleaner and smoother compounds has beenrapid, as most utilities specified these materialsin 2004.Polyethylene manufacturers have focused on

material purity, improvement in the compound-ing and process design, and quality assuranceand quality control improvements. In addition,delivery systems have dramatically improvedover the past 15 years. Using dedicated reactors,upgrading reactor clean out and defouling proce-dures, and monitoring each run for ambers andgels have improved manufacturing technology.Increasing the raw material cleanliness, filtratingall process air and water, and operating under asealed loop strategy have helped to ensure abetter product. In addition, handling systemsnow use gravity feed and dense phase, as wellas dedicated, sealed rail cars in good condition.Polyethylene is manufactured by compound

suppliers and shipped in pellet form to the cablemanufacturers for extrusion onto the full-sizedcable. Contamination is possible at any stepalong the way. Most manufacturers carry out op-tical pellet inspection, but usually only abouttwo percent of the total amount of compound isinspected. Needless to say, many contaminantsare missed, as recent statistics suggest that eventhe cleanest compound can contain contaminantsabove 12 mils, and these may be removed with

100 percent pellet inspection. Ideally, the pelletinspection should take place as close to themanufacturer’s extruder head as possible andnot contribute to further contamination.Currently, pellet inspection devices are avail-

able for use at the cable manufacturer’s plant.The inspection devices remove loose contami-nants and surface contaminants as well as pel-lets containing embedded contaminants. Allmodels come with a self-enclosed air filtrationsystem that provides a Class 1000 environmentunder a plastic curtain surrounding the unit. Re-moval of contaminants starts at three mils andoptimizes at 12 mils.Inspection of EPR is more difficult, as the ma-

terial is opaque. Tape inspection devices canalso be used for surface inspection of extrudedEPR sample tapes.Also available are inspection devices for gels

in polymers and for small defects in interfaces.Although interfacial inspection does not occuruntil after the cable is manufactured, this latterdevice does provide an opportunity to identify,locate, and remove interfacial problems beforeshipment.Although inspection for contaminants is im-

portant, it is also important to eliminate all possi-ble sources of contamination during the manu-facturing of not only the insulation system butalso the conductor and insulation shields. Thismeans controlling the contact of possible conta-minants, especially airborne dust particles, toraw insulation materials or to the cable duringextrusion. Materials should be exposed as littleas possible to the ambient air in the plant. In ad-dition, cable interface surfaces should, similarly,have minimum possible exposure to an uncon-trolled environment during the extrusion process.

EXTRUSION AND CURING PROCESSESDuring cable manufacture, the various shieldsand insulating layers are extruded over the con-ductor. The raw material is melted and the liq-uid polymer is pumped into a die that applies acontinuous and uniform layer around the con-ductor. The material is then cured at the propertemperature for the proper time. This process isrepeated for various layers until the desiredcable configuration is achieved.

2

62 – Sect ion 2

Expediency and quality in cable manufacturecan be achieved if the extrusion of different lay-ers is performed simultaneously. The industryuses multiple simultaneous extrusion processes.Figure 2.7 shows the general layout of a cableextrusion line. The conductor enters the processfrom the pay-off reel. The conductor first passesthrough the extrusion heads, where the shieldsand insulation are applied. The cable then en-ters the curing tube, where the extruded poly-mers are cured at a temperature between 218°C(425°F) and 293°C (560°F). Pressure in the cur-ing tubes is also maintained between 150 and300 psi. This temperature and pressure is main-tained long enough for cross-linking to takeplace in the insulation and/or shields. Aftercuring, the cable enters a cooling zone, com-monly referred to as a water bath or quenching.However, some new production lines use drygas cooling.The methods used to cure and cool the cable

during manufacture are the subject of much re-search. Older systems used high-pressure steamfor curing, which led to higher water content(5,000 parts per million) within the insulation. Itis suspected that this insulation water contentmay contribute to the development of water

2

Extrusion Area– Conductor Shield– Insulation– Insulation Shield

Curing Tube

Water Cooling

Take-Up Reel

Pay-Off Reel

Insulated Cable

Bare Conductor

FIGURE 2.7: General Layout of a Cable Extrusion Line.

trees within polyethylene. Some newer equip-ment uses dry nitrogen as a heat transfer agentin the curing tube, which eliminates insulationcontact with water until it has solidified. The re-sult is lower water content (200 ppm) in the in-sulation. The few cable production lines that usedry gas for both curing and cooling achieveeven lower water content (50 ppm). The signifi-cance of the lower water content is still the sub-ject of continuing investigation. It is believedthat the very lowest water contents are main-tained in service only if the cables are com-pletely sealed from moisture. However, theindustry has widely accepted the desirability of dry nitrogen gas curing, especially for poly-ethylene-based cables.Steam curing is the oldest cross-linking or vul-

canizing method employed in any continuousvulcanizing (CV) plant. In steam curing, thefreshly extruded cable passes down the center of a long vulcanizing tube filled with saturatedsteam at about 20 atmospheres (300 pounds per square inch gauge (psig)) pressure and temperature of about 215°C (419°F). The curedinsulation is then cooled under pressure by coldwater. Most EPRs are still made with steam curing in a CV catenary process.


Dry curing, on the otherhand, consists of an electri-cally heated tube filled withhigh-purity nitrogen gas atabout 10 atmospheres (150psig) pressure. The infraredenergy emitted by the hottubes is transferred to thecable components. The cable surface tempera-ture can be as high as 300°C (572°F). The curedcable is cooled by passing through a coolingsection containing water under the same pres-sure as the curing section to prevent void forma-tion in the insulation. A dry cured insulationcontains voids in the order of 100/mm3, 1 to 10µm (micrometers) in size, whereas steam curinggenerates voids of 105/mm3, 1 to 50 µm in size.Sixty percent of the investor-owned utilities nowspecify dry curing. Of the remainder, 33 percent

2

FIGURE 2.8: Typical Extrusion Methods.

are EPR users who gain littleadvantage in the dry cure tech-nology. Most utilities that spec-ify EPR insulation requeststeam curing or do not specifya curing method at all.For UD cable production,

the triple extrusion and the drycure technology with the catenary arrangementis most common.Extrusion heads are continuing to evolve. The

simplest head configuration is the two-pass (ordual-tandem) process shown in Figure 2.8(a). Adisadvantage of this arrangement is the openspace between the application point for the con-ductor shield and that for the insulation. Theconductor shield surface can be contaminatedby airborne particles. In addition, the cablemust be returned to a separate extrusion line

True triple-tandem

extrusion

is preferred.

Insulation Insulation Shield

Insulated Conductor with

Insulation ShieldBare Conductor Conductor Shield Added

First Pass

(a) 2 Pass or Dual-Tandem Method

Second Pass

Insulated Conductor Insulated Conductor

Conductor Shield

Insulation

Insulation Shield

Insulated Conductor with Insulation ShieldBare Conductor Conductor Shield Added

(b) 1 + 2 Triple-Tandem Method

Conductor Shield

Insulation

Insulation Shield

Insulated Conductor with Insulation ShieldBare Conductor

(c) 3-in-1 Triple Method

Conductor Shield

64 – Sect ion 2

for installation of the insulation shield. This isalso an opportunity for contamination of a criti-cal interface surface.A major improvement in cable extrusion is

the development of the 1 + 2 triple-tandemarrangement. Here, the insulation and the insu-lation shield are extruded simultaneously asshown in Figure 2.8(b). Though there is still achance for airborne contamination between theconductor shield head and the insula-tion/insulation shield head, there is no chanceof contamination on the insulation surface.The latest extrusion configuration is the true

triple-head unit. All three compounds are ex-truded simultaneously in one location in a

completely enclosed head [see Figure 2.8(c)]. Si-multaneous extrusion eliminates the opportunityfor contamination of any interface surface.Today, the preferred extrusion method is the

triple crosshead line or the true triple-head ex-truder. This line features one common crossheadconnecting three extruders, so that the insulationand the semiconductive shields are extruded si-multaneously over the conductor. With its suc-cessful development and commercialization, thetriple crosshead is now generally accepted inthe industry because it minimizes the chance ofdamage and contamination at the shields and in-sulation interfaces. Most utilities now specify thisextrusion method.

2

Conductor Shields and Insulation Shields

Conductor shields and insulation shields sharethe function of providing a uniform cylindricalsurface on either side of the cable insulation,which allows the most uniform possible distrib-ution of electrical stress. The conductor shieldis particularly important in reducing stress con-centrations caused by stranded conductors orimperfections on the conductor surface. The in-sulation shield eliminates nonuniform voltagegradients in the insulation caused by irregularcontacts with grounded objects. By producing a more uniform electrical stress distribution,shields allow thinner insulation sections to beused with more predictable results.Before the general acceptance of extruded di-

electric cables, the conductor shield and the insu-lation shield both usually consisted of carbon-loaded cotton tape. These tapes improved thesurface contour of conventional stranded con-ductors and were generally suitable for use withpaper and rubber insulation compounds. Withthe advent of extruded polyethylene dielectrics,extruded shields gained favor. These could beapplied at a lower cost and produce a more uni-form surface than could semiconducting clothtapes. This more uniform surface was particular-ly important for gaining cable reliability withpolyethylene cable insulation.Present practice in extruded insulation cables

uses extruded conductor and insulation shieldsalmost exclusively. The preferred material is asemiconducting version of the material used for

the cable insulation. For instance, if the cable isinsulated with cross-linked polyethylene, a semi-conducting XLPE would be applied for both theconductor shield and the insulation shield. Simi-larly, cables insulated with ethylene propylenerubber could have a semiconducting EPR com-pound or a similar compound, such as ethylvinyl acetate (EVA), as shielding material. Thiscombination produces the greatest insulationsystem component compatibility. It is particu-larly important to have very similar coefficientsof thermal expansion to minimize the generationof thermal stresses within the cable at extremeoperating temperatures. Other combinationsmay be used if elasticity and tensile strengthcharacteristics are compatible. Most manufactur-ers use EVA for these shields.

CONDUCTOR SHIELDFor maximum effectiveness, the conductor shieldshould be firmly bonded to the cable insulationto minimize voids at the interface between thesetwo components. Because this zone has thehighest electrical stresses in the cable and voidswill produce insulation deterioration under elec-trical stress, it is particularly important to havethe minimum number of possible voids in thislocation. The extruded conductor shield materialshould strip freely from the conductor withoutleaving residue to facilitate cable splicing. Other-wise, particles of semiconducting polymer mightbe left inside electrical connections that would


unacceptably impair conduc-tivity within the connections.ANSI/ICEA Specification

S-94-649-2000 allows the con-ductor shield/insulation inter-face to have protrusions ofseven mils (0.18 mm) into theconductor shield and five mils(0.127 mm) into the insulation,if standard conductor shieldthicknesses are used. Voids ofup to three mils (0.076 mm) are allowed at thisinterface. Research on cable failures has shownthat most electrochemical trees begin at voids orprotrusions near the conductor shield/insulationinterface. Tree inception at these points is be-cause of the extremely high electrical stresses inthese regions and because these irregularitiesserve as stress amplifiers when they produce anonuniform electrical field. The cable industryhas, therefore, developed the concept of a su-persmooth conductor shield that produces anextruded conductor shield with a much moreuniform cylindrical surface. Protrusions into thecable insulation are reduced in size and quanti-ty. Typical interface irregularities for these im-proved conductor shield materials are approxi-mately one percent of the size found in conven-tional shields. This significantly reduces thenumber of tree initiation sites in the section ofinsulation with the highest electrical stresses. Be-cause reducing irregularities and voids in thisarea will yield longer cable life, the cable pur-chaser should strongly consider using the ad-vanced conductor shield systems with improvedsmoothness. Such materials may be slightlymore expensive, but the total life-cycle cost ofthe cable may be lower because the cable fail-ure rate may be reduced.

INSULATION SHIELDThe cable insulation shield forms a cylindricalsemiconducting surface on the outside of the in-sulation, which is essential to avoid nonuniformelectrical stresses in the insulation. Although it istheoretically possible to place a uniform con-ducting metallic shield directly outside the cableinsulation, it is impractical to achieve and main-tain the continuous intimate contact required to

2avoid stress concentrations orcorona-producing voids.Therefore, an extruded semi-conducting insulation shield isinstalled to evenly distributeelectrical stresses. An extrudedshield of a compatible materialwill tightly adhere to the insu-lation, even when the cable isbent or compressed. Theshield will also remain in close

contact when the cable is operated at extremelydesign temperatures.The cable insulation shield must have unvary-

ing conductivity characteristics to serve as an ef-fective shield and produce a uniform, equipoten-tial surface. In addition, the insulation shieldmust carry the cable capacitive currents betweenthe insulation shield interface and the groundedmetallic shield tape or conductors. This capabili-ty is particularly important where a concentricneutral configuration is used with conductorsspaced around the cable circumference. Underthese conditions, the insulation shield must carrycurrents transversely as well as radially. The con-centric neutral configuration makes the distancetraveled by the capacitive currents greater andmakes shield uniformity even more important(see Figure 2.9). Current concentrations underthe concentric neutral strand also make it impor-tant to keep shield resistivity low.The cable insulation shield must maintain

good contact with the insulation, yet be easy toremove during splicing. If the insulation shield isfirmly bonded to the insulation, this bond willproduce ideal electrical properties, but it willmake splicing much more difficult. Firm bondingwill require cutting the shield from the insula-tion, which must be done very carefully to keepa uniform cylindrical outer surface on the insula-tion. Therefore, where splicing or terminationsare required frequently, the insulation shieldshould be free-stripping. Removal should leaveno residue on the insulation surface. The cablespecifier should note any special conditions ofcable use, such as low splicing temperatures,that may require special stripping characteristics.However, to maintain acceptable electrical per-formance, certain minimum stripping force will

Most electrochemical

trees begin at voids

or protrusions near

the conductor shield/

insulation interface.

66 – Sect ion 2

be required. If the minimum bonding is notmaintained, insulation-damaging corona mightbe produced at the insulation interface, espe-cially in cable bends. Because good adherence isnecessary for satisfactory electrical performance,the installation crews may have to warm the in-sulation shield to an acceptable temperature forsplicing and termination. If such conditions arefrequently encountered, the cable specifier maywish to cite special conditions in the cable speci-fication and call for special low-temperaturestripping tests. However, the specifier should al-ways remember that long-term performance ofthe cable is the most important criterion andspecial installation techniques may be neededunder low-temperature conditions.Pending RUS 1728F-U1 specifications for pri-

mary cables call for minimum and maximumtension ratings for “strippability” of insulationshields, as shown in Table 2.5. Slightly differentlimits for stripping tension are used in the sam-ple cable specification contained in Appendix E.If a cable system is going to be used in an in-

stallation requiring especially high reliability andfew splices or terminations, the specifier mayuse a firmly bonded extruded insulation shield.Doing so will produce optimum electrical perfor-mance. If long cable pulls are used, less extralabor will be needed to make splices. However,before starting installations of this type, crewsmust be specially trained and proper tools mustbe obtained to make satisfactory splices. Firmlybonded insulation shields should never be usedon underground residential systems where cables are frequently terminated.

CONCENTRIC NEUTRALS AND CONDUCTIVE METALLIC SHIELDSShielded cable systems require not only a semi-conducting insulation shield but also a conduc-tive metal shield to function properly. The metalshield is in intimate contact with the semicon-ducting insulation shield. The major functions ofthe conductive metal shield are the following:

• To serve as a grounding means for the semi-conducting insulation shield to keep allsections at constant potential,

2

FIGURE 2.9: Capacitive and Dielectric Loss Current Flow in InsulationShield.

Concentric Neutral Strand

Concentric Neutral Strand

Insulation

Strand Shield

Conductor

SemiconductingInsulation Shield

SemiconductingInsulation Shield

Capacitive Current Flow

Minimum Maximum Cable Removal Removal

Insulation Type Tension (lb.) Tension (lb.)

EPR 3 18

TR-XLPE 6 16

Discharge Resistant 0 16

TABLE 2.5: Insulation Shield StrippabilityRatings.


• To serve as a path for currents generated bycapacitive couplingbetween the central conductor and the system neutral or the surrounding earth,

• To serve as an interceptorof system fault currents in case of a dielectric failure,

• To provide a grounded metallic objectbetween the energized conductor and thecable exterior, and

• To serve as a system neutral (in some cases).

All these functions are extremely important.The conductive shield’s failure to properly per-form any of these functions will lead to either acable failure or a malfunction of the electric dis-tribution system in which the cable is installed.A wide variety of conductive shield configura-

tions have been developed for use on cable sys-tems. Examples of typical shield configurationsare given below.

CONCENTRIC NEUTRALSConcentric neutral conductors serve a dual roleas a conductive cable shield and a circuit neu-tral. To fulfill this second function, the shield(neutral) has a much larger cross section than istypical with flat tape, drain wire, or L.C. shieldconfigurations. Typical concentric neutral cableswill have a neutral conductivity equal to that ofthe central conductor (full neutral), or one-third

2to one-half (reduced neutral)of the phase conductivity. Thisenables the cable to functionwithout a separate neutral con-ductor. Mechanical as well aselectrical considerations gener-ally mandate that concentricneutral conductors be copper,

even if the central cable conductor is aluminum.Table 2.6 shows concentric neutral sizes oftenused on distribution cables.Full-capacity concentric neutrals are most

often used on smaller cables that are applied insingle-phase circuits. Having full conductivity inthe neutral reduces circuit voltage drop. The sys-tem neutral-to-earth voltage under both normalloads and fault conditions is reduced as well.Reduced neutral capacities are most often

used on three-phase circuits, particularly in thelarger conductor sizes. Doing so is feasible anddesirable because of the following:

• In a three-phase circuit, three neutrals areconnected in parallel, which reduces the crosssection required to produce a full-capacitysystem neutral to one-third on each cable.

• In a three-phase system, system neutral returncurrent should be near zero, thereby reducingthe cross-sectional area required to maintainlow system losses and neutral-to-earth volt-ages under reasonably balanced conditions.

• In a three-phase cable system with intercon-nected neutrals, losses in the cable neutral arecaused by circulating currents. All other factors

Defects in the shield

system will cause

cable failures.

Typical Neutral Configuration

Conductor Size Full Capacity One-Third Capacity One-Sixth Capacity One-Twelfth Capacity

#2 AWG Aluminum 10 × 14 AWG 6 × 14 AWG N/A N/A

1/0 AWG Aluminum 16 × 14 AWG 6 × 14 AWG N/A N/A

4/0 AWG Aluminum 13 × 10 AWG 11 × 14 AWG N/A N/A

350 kcmil Aluminum 20 × 10 AWG 18 × 14 AWG 14 × 16 AWG N/A

500 kcmil Aluminum N/A 16 × 12 AWG 20 × 16 AWG 10 × 16 AWG

750 kcmil Aluminum N/A 20 × 9 AWG 30 × 16 AWG 10 × 14 AWG

TABLE 2.6: Concentric Neutral Configurations for Common Aluminum Cables.

68 – Sect ion 2

being equal, these losses are lower where thereis less neutral conductivity. A cable with aone-third neutral has 53 percent of the lossesof a cable with a full-capacity neutral if thecables are spaced 7.5 inches center to center.The circuit ampacity of full-neutral cables inthree-phase circuits is also reduced becauseof these shield losses. This problem is signifi-cant in larger cable sizes, particularly if thecables are not closely grouped. For instance,on a 350-kcmil circuit carrying 390 amperes,the losses on a circuit with 7.5-inch cablespacing will drop from 12 kW/1,000 feet to6.4 kW/1,000 feet if a one-third neutral is usedinstead of a full-capacity neutral. Elevatedlosses and reduced ampacities are not gener-ally a problem on three-phase circuits of 1/0AWG aluminum or smaller if the cables aregrouped in a single trench. Additional infor-mation on circuit ampacity rating for variousneutral configurations is given in Section 4.

Longitudinally Corrugated ShieldThe L.C. shield has been developed as a way toprovide greater conductivity in larger cables. Theshield generally consists of a copper sheet thatis installed with its major axis parallel to that ofthe cable. The sheet is then folded around thecable and sealed to itself on the opposite side.Circumferential corrugations are fabricated in theresulting tube to add flexibility and ensure thatthe shield will uniformly bend with the cable. Theseal applied between the two sides of the copperis usually an adhesive elastomer. The tube gen-erally does not have a metal-to-metal connectionwith the cable insulation shield at this point be-cause allowance must be made for the cable in-sulation to thermally expand during operation atelevated temperatures. Not only is the tempera-ture change higher in the insulation than it is inthe cable shield, but all dielectrics have a sub-stantially higher coefficient of thermal expansionthan that of copper. Because the metallic shieldmust have good contact with the semiconduct-ing insulation shield to function effectively, atight fit must be maintained at all times. There-fore, the insulation expansion is accommodatedby flexibility in the elastomeric seal. The returnof the shield to intimate contact as the cablecools is assisted by the external insulating jacket.

2

Equation 2.2

where: A = Cross-sectional area, in cmils

b = Tape thickness, in mils

dm = Mean diameter, in mils

W = Width of tape, in mils

L = Overlap of tape, in mils

A = 4bdm × W

2(W – L)

L.C. shields are commonly available in five-milthickness but, for applications requiring additionalfault current capability, shield thicknesses of eightor 10 mils can be furnished. However, L.C. shieldsshould be sized to carry expected system neutralcurrents. Use of L.C. shields as the system neutralwill require evaluation of available system faultcurrents and protective system clearing times. Ac-cessories such as shield (neutral) bonding clampsmust also be carefully evaluated for long-termcontinuous current and fault current capacity.The L.C. shield does provide a limited degree

of resistance to water vapor transmission. It isclearly superior to concentric neutral configura-tions for water vapor transmission. It is some-what better than helically applied copper tapeshields because the length of the straight joint isless than the helical joint. Moreover, the elas-tomer at the lap point does provide a better seal,although, under static pressure, the elastomericseal cannot be depended on to prevent moisturefrom migrating into the cable insulation.

Flat Copper TapeThis is perhaps the oldest conductive shield con-figuration. The tape generally consists of a five-mil(0.005-inch) thick copper tape helically appliedover the semiconducting insulation shield. The tapeis usually installed with a 12.5 percent overlap.Tape shields may be fabricated from bare copperor may be tinned copper. Because of the smallcross section, the conductivity of flat copper tapeshields is relatively low compared with the centralcable conductor. Equation 2.2 gives the effectivecross-sectional area of an overlapped tape.


CONCENTRIC NEUTRAL CONFIGURATIONSAs experience has been gained with under-ground installations under a variety of condi-tions, the utility industry has developed severalspecialized variations of the basic concentricneutral configurations. Each of these arrange-ments has an advantage for a particular set ofinstallation conditions.

Bare Concentric NeutralThe first widely accepted concentric neutral cableswere of a bare concentric neutral (BCN) config-uration. In this design, the concentric neutralstrands were laid over the semiconducting insu-lation shield and no jacket was applied. When thecable was directly buried, this arrangement hadthe advantage of exposing the concentric neutralconductors to the surrounding soil. The result wasa very effective ground, especially where soil re-sistivity was low. The low resistance betweenneutral and earth meant more of the system neu-tral current could return to the source by way ofthe earth, thereby reducing current in the con-centric neutral and circuit voltage drop. Further-more, the low resistance between the neutraland earth reduced neutral-to-earth voltages dur-ing both normal operations and fault conditions.The bare concentric neutral is also considered

the best possible arrangement for personnelsafety in case of a dig-in. The neutral size en-sures the ability to adequately conduct fault cur-rents until protective devices operate. The high-er conductivity of the concentric neutral willproduce lower voltages on the neutral at thefault location. The low resistance between theneutral and earth will significantly reduce thetouch potential at the dig-in site. Most important,the concentric neutral physical arrangement en-sures the object penetrating the cable will haveestablished a good neutral connection beforecontacting the energized center conductor.In light of all the advantages of BCN cables, it

is unfortunate that there are major durability prob-lems with this design under many installationconditions. These problems are all related tocorrosion of the exposed cable neutral. In manycases, the neutral had a significantly reducedcross section after only a few years of service. Inother cases, the neutral was completely corrodedand the only neutral current path was through

ground rods. This condition was totally unsatisfac-tory from the standpoints of system safety and re-liability. Therefore, the use of BCN cable has beendiscontinued except in very special conditions.

Jacketed Concentric NeutralBecause of the very serious problems experi-enced with BCN cables, the electric utility indus-try began using the jacketed concentric neutral(JCN) configuration. This configuration has mostof the major advantages of the BCN design ex-cept for continuous contact of the neutral withearth. The jacketed configuration reduces accessof moisture and corrosive agents to the neutral.Insulating jackets also interrupt the flow of gal-vanic corrosion currents between the neutraland other metallic objects.JCN design has achieved wide acceptance as

a solution to the concentric neutral corrosionproblem. However, the cooperative engineermust give special attention to system groundingif jacketed cables are used. Cable identificationalso acquires additional importance, as jacketedcables are approximately the same dimensionand general appearance as many communica-tion cables and water lines. See Section 5 in theDesign Manual for detailed information on sys-tem grounding.

Flat-Strap Concentric NeutralsFlat-strap concentric neutrals, not to be confusedwith flat-tape metallic shields, consist of helicallyapplied flat copper straps. These straps are about0.020 to 0.025 inches (20 to 25 mils) thick andabout 0.150 to 0.175 inches wide. The straps areapplied so they abut each other and provide 90percent metallic coverage over the outside ofthe cable. Conductivity of flat-strap neutrals isgenerally equal to that of the energized conduc-tor. Flat-strap concentric neutrals have foundgreatest acceptance in areas where rodents dam-age direct-buried cables. The complete metalliccoverage on a cable was originally believed tolessen damage from gophers. However, usingthis type of cable to lessen rodent damage hashad mixed results. Recent research shows thatrodent damage is more effectively limited by in-creasing the diameter of the object. Therefore,flat-strap neutrals should not be depended on toprevent rodent damage.

2

70 – Sect ion 2

Flat-strap neutral cablesshould be jacketed. The thick-ness of the flat strap is lessthan the diameter of the neu-tral wires. Therefore, the com-plete cable diameter will beless. This is an advantagewhere space is limited.

Concentric Neutral Materials Other Than CopperThe predominant material in concentric neutralshas always been copper. For many years, thegenerally accepted wire for bare concentric neu-trals was copper with a tin or tin-lead alloy coat-ing. As experience has been gained with a widevariety of materials, engineers have determinedthat the coating of the copper concentric neutralconductors was not necessary and, in some cas-es, actually led to higher corrosion rates. It isgenerally believed that, in the early days of con-centric neutral cable manufacture, tinned copperconcentric neutrals gained wide acceptance be-cause most flat-tape metallic shields were tinnedon jacketed cables. In some cases, that was aholdover from cables on which butyl rubber in-sulation was used and tinning was needed toavoid corrosion. Also, tinned copper was usedon earlier cables because of the prevalence ofsoldered connections, and the coated copper fa-cilitated soldering of these thin shields. Becauseconcentric neutral cables never employ solderedconnections and butyl rubber is no longer usedfor insulation, the need for coating neutral wireshas disappeared. Bare copper wires are nowuniformly accepted as the preferred material forconcentric neutrals, whether bare or jacketed.During the mid-1970s, a few utilities briefly

experimented with aluminum concentric neutralcables. These were applied in a bare configura-tion. Although some laboratory studies showedthat the aluminum neutrals would resist manytypes of soil-induced corrosion, field experienceproved quite the opposite. The very complex in-teractions present on an interconnected neutralpassing through a variety of soils led to earlyfailure of these cables. It became obvious thataluminum should never be used as an exposedconcentric neutral in direct-buried or conduitcable installations.

Experience with low-voltageinsulated cables has shownthat aluminum conductors canbe extremely susceptible tocorrosion, even if they are in-sulated from the surroundingenvironment. Because cablejackets are not absolutely

moisture proof, even an encapsulated alumi numneutral conductor may be subject to long-termdeterioration from moisture migration. It is un-wise to consider aluminum neutral conductorsfor primary cables, even in a jacketed configura-tion, when the only advantage to be gained isslight savings in initial material cost.Another approach that was used for a limited

time to try to solve the bare concentric neutralcorrosion problem was the use of a compositecopper/steel conductor. The particular configura-tion used a copper center core for conductivity,with a heavy steel coating completely surround-ing the copper. For durability during periods ofatmospheric exposure, the steel was galvanized.This cross-sectional arrangement offered the def-inite advantage of having steel exposed to theearth in the direct-buried cables instead of cop-per. The exposed steel greatly simplified the ap-plication of cathodic protection systems to theneutral. However, the conductor used in thisneutral construction did carry a premium price.Utilities also experienced difficulty in applyingthis cable to existing systems that already hadextensive exposure of bare copper concentricneutrals. Systems containing this cable configu-ration required sacrificial anodes or impressedvoltage rectifiers applied to provide protectionto the neutral. For additional information on theprinciples of cathodic protection, see Section 7.

CABLE JACKETIn most cables, the cable jacket is the outermostlayer of material that serves as a barrier to mois-ture and mechanical damage. Therefore, it is im-portant to optimize the design and materials ofthe jacket to obtain maximum performance inthese important areas.For many years, all power cable designs includ-

ed a jacket. However, with the advent of the ex-tensive underground residential programs, electricutilities began installing bare concentric neutral

2Always specify

copper for concentric

neutral conductors.


cables. This design eliminated the cable jacket sothat the BCN could establish conductive contactwith the earth in a direct-buried installation. En-gineers eventually learned that the acceleratedfailure rate of UD cable was largely caused bycable moisture and/or concentric neutral corro-sion. Both of these factors were able to stronglyinfluence UD cable life because of the lack of ahigh-quality cable jacket. It is worth noting that,although U.S. utilities installed BCN UD cables,European and Japanese utilities continued to installonly jacketed cables. These utilities have experi-enced much higher distribution system cable relia-bility than has been typical in the United States.Recognizing this, the U.S. electric utility industrynow mainly uses jacketed cables. These may beconventional power cables with flat-tape or drain-wire shields, or they may be JCN cables. Jacketscan be either insulating or semiconducting.Under any circumstances, the jacket material

is very important. Desirable characteristics in-clude abrasion resistance, flexibility, and lowmoisture permeability. If cable is being pulled

into a conduit system, a low coefficient of fric-tion with the conduit material is desirable.Today, most utilities specify an outer jacket.A wide variety of chemical components have

been used successfully for cable jacketing. Thematerial most desirable for jacketing is linearlow-density polyethylene (LLDPE). This materialhas the best balance of properties for use on un-derground utility cables.Table 2.7 shows a comparison of important

properties of various compounds. The tableshows that polyethylene is preferable in almostall categories except fire resistance. In direct-buried applications and outdoor conduit installa-tions, this compromise is acceptable. Lowchlorine content is an advantage because hydro-gen chloride may result from these compoundsat the emergency operating temperature of130°C (266°F). This gas, particularly in conjunc-tion with surrounding moisture, will be detri-mental to XLPE and EPR insulating compoundsas well as copper neutrals or other metallicshield materials.

2

Semiconducting Polyethylene (PE) Polyethylene* Polyvinyl Chloride (PVC)

Physical Properties • Tensile Strength (psi) 2,730 1,700 1,920• Elongation 620 450 350

Moisture Transmission 7 Days in 70°C (158°F) Water• Grams/m2/24 hours 0.8 1.5 >10

Flame Resistance 20 Min. at 70,000 Btu/Hr• Cable Tray Fire Test Fail Fail Fail**

Low Temperature Properties Cold Bend Test• Temperature Passed (°C) -40 -50 -10

Chlorine Content (%) 0 0 22.0

Thermal Stability• Initial Temperature of

Decomposition (°C) 350 350 160

* Based on Union Carbide 7708.** PVC can be specially compounded to pass the Cable Tray Fire Test.

TABLE 2.7: Comparison of Jacketing Material Test Data.

72 – Sect ion 2

Another important characteristic of jacketingmaterials is the coefficient of friction in commonpulling situations. Table 2.8 shows the static co-efficient of friction of various jacket materials inPVC conduit.Jacket materials used on utility systems

should always be sunlight-resistant. Very few installed utility cables have no part of the cableever exposed to sunlight. Therefore, most cablejacketing compounds will be colored black toeliminate sunlight penetration and, thereby, en-hance the natural durability of the basic jacketcompound.

Jacket ConfigurationsThere are two main physical arrangements forcable jackets. The first significant jacket configu-ration is the encapsulating jacket. This arrange-ment surrounds the concentric neutral conductorswith the jacketing compound. The jacket is ex-truded directly over the concentric neutral strands.The jacket material fills all areas between con-centric neutral strands and establishes close con-tact with the semiconducting insulation shield.Adequate jacket thickness is placed over theoutside of the strands to minimize the chance ofstrand exposure during installation. The advan-tage of this encapsulated neutral design is thatno spaces exist between neutral strands to allowmovement of moisture along the cable. There-fore, any penetration will allow moisture in onlyone small spot, and probably will expose onlyone neutral strand at this location. Limitingmoisture exposure to only one strand of theconcentric neutral will reduce the potential forloss of neutral continuity.The second jacket configuration is an ex-

truded jacket that overlays the metallic shield orconcentric neutral. In this arrangement, thejacket is often separated from the tape shield,

2drain wires, or concentric neutral by a nonad-hering tape. This tape keeps the two layers en-tirely separate. Where drain wires or concentricneutrals are used under the jacket, this methodleaves an annular (ring-shaped) space betweenthe semiconducting insulation shield and theoutside jacket. Although this space does containthe metallic wire shield, the spaces betweenstrands become a reservoir for moisture that mayenter the jacket through gradual absorption,manufacturing defects, or installation-induceddamage. This space also provides an excellentpath for migration of moisture along the lengthof the cable. This moisture is extremely detri-mental to the cable by its promotion of electro-chemical treeing in the insulation. This moisturealso facilitates corrosion attacks on metallic shieldstrands. Although this jacket configuration is sat-isfactory for use with metal tape shields, itshould not be used with concentric neutral ca-bles that will frequently be exposed to moisture.

Semiconducting JacketsThe use of insulating jackets on direct-buriedcable improves most performance characteristics,with one major exception. Use of an insulatingjacket deprives the concentric neutral of its con-ductive contact with the surrounding earth,thereby relegating all system neutral groundingto driven rods or other electrodes installed alongthe circuit route. To improve cable groundingwith its attendant benefits, a semiconductingcable jacket was introduced. The jacket consistsof a semiconducting compound that is extrudedin an encapsulating jacket (embedded neutral)configuration. The constructed cable has a radialresistivity of less than 100 meter-ohms and is,therefore, comparable to the conductivity ofmost soils. This ensures neutral-to-earth currenttransfer comparable to that of a BCN design.The improvement of conductivity provided by

semiconducting jackets between the concentricneutral and the surrounding earth is a significantimprovement in overall UD system design. How-ever, there are some disadvantages to the semi-conducting jackets. These disadvantages areprincipally associated with the greater moisturetransmission rate of the semiconducting polyeth-ylene compound. The first semiconducting jackets

Polyvinyl Cross-Linked High-Molecular-Weight Linear Low-Density Chloride Polyethylene Polyethylene Polyethylene

(XLPE) (HMWPE) (LLDPE)

0.69 0.75 0.42 0.42

TABLE 2.8: Static Coefficient of Friction for Jacketing Materials in PVCConduit.


deterioration of interconnected steel is not a sig-nificant problem.In summary, utilities should carefully consider

all aspects of the system performance before in-stalling semiconducting jackets on direct-buriedcable. Though the advantage of lower system re-sistance to remote earth is desirable and immedi-ate, the potential subtle negative effects are long-term and may have an effect on the useful life ofthe cable. The utility should consider the partic-ular circumstances of the proposed installationconditions and weigh the merits of each cablejacket option.

Cable Jacket MarkingExternal marking of jacketed cable is necessaryand serves three major purposes. The first is toprovide information on the cable’s characteris-tics. The conductor size, type and thickness ofinsulation, and voltage rating must be included.The manufacturer’s name and the year of manu-facture must also be included. All these mark-ings must be durable and indented into (orembossed onto) the jacket.The second purpose is to make individual

cable identification and accounting easier by ap-plying sequential footage markers to the outsideof the jacket. These markings should be appliedwith the general cable information listed above.These markings, along with reel label data, tellthe installer how much cable remains on a reel.The sequential footage markings also help iden-tify a particular cable that may be exposed in themidpoint of a multiconductor run.The third important purpose of external mark-

ings is to identify JCN cables as high-voltage ca-bles. If unmarked, JCN cables are indistinguish-able from jacketed communications cables. Thisdifference must be made clear to personnel ofall utilities. Previous efforts have involved theapplication of three red stripes in the cable sur-face. Other schemes have used various patternsof raised ribs on the cable surface. To assist insolving this problem, the NESC (ANSI StandardC2) requires that all electric supply cables have astandard lightning bolt symbol included in theexternal marking. This symbol is illustrated inFigure 2.10. As with all other exterior markings,it must be durable and indented into (or em-bossed onto) the cable surface.

2

FIGURE 2.10: Cable Identification Markings. Source: ANSI/IEEE C2(NESC).

had moisture transmission rates approximately12 times that of LLDPE. At that level, moisturecould penetrate the jacket and collect adjacentto the concentric neutral strands. There themoisture had the potential to serve as an elec-trolyte, forming a galvanic cell between the cop-per neutral and the carbon in the semiconduct-ing jacket. This could result in deterioration ofthe neutral. Another aspect of the semiconduct-ing jacketed cable design concerns the possibili-ty of mechanical damage to the jacket during in-stallation, exposing the neutral conductors di-rectly to the soil. In this case, there is the poten-tial for the galvanic attack to be more severe be-cause the ratio of exposed surface areas of thecarbon to copper is much greater. There also previously existed concern that the

galvanic cell existing between the semiconduct-ing jacket and interconnected subterranean steelobjects might be detrimental to the steel. Examplesof such objects are anchors, telephone pedestals,and water piping. Tests have been conducted by NEETRAC to demonstrate that accelerated

Printed Data

Clear Space

Symbol for Communication Cable

Symbol for Supply Cable

H = Height of printed characters; determined by cable manufacturer

3H3H 3H

Printed Data

Clear Space

3H3H 3H

H

H

74 – Sect ion 2

Acquisition of satisfactory cable starts withpreparing an adequate specification documentthat fully describes the cable needed. As thepreceding topics in this section have shown,there are many options from which to choose.The specification must describe the following:

• The cable that will best fulfill system requirements,

• The quality control tests that are expectedduring and after manufacture, and

• The packaging and shipping methods to be used.

In short, all items of importance to the pur-chaser must be described either directly orthrough reference to other industry-standardspecifications.Reference to industry-standard specifications

can greatly simplify the specification-writingprocess for both the purchaser and the supplier.Perhaps the most notable examples of widelyaccepted U.S. cable specifications are those pre-pared under the auspices of the ANSI/ICEA.ANSI/ICEA Specification S-94-649 covers cablesinsulated with thermoplastic, cross-linked, andethylene propylene rubber. This specification isfor shielded cables rated five through 46 kV.Within these specifications, there are referencesto various detailed specifications, such as NationalEquipment Manufacturers Association and ASTMspecifications.Another major specification that affects rural

electric cooperatives is RUS Bulletin 1728F-U1.The RUS U1 specification makes extensive refer-ence to ANSI/ICEA Specification S-94-649-2000.U1 is oriented specifically to UD cables up to 35 kV and optional semiconducting outer jack-ets. As of the writing of this manual, this RUSBulletin 1728F-U1 is still pending final approval.Compliance with these commonly accepted

electric industry specifications assures the pur-chaser that the manufacturers will be familiarwith the general requirements and should havedesigns and quality control procedures in placeto meet the purchaser’s needs.

SAMPLE CABLE SPECIFICATIONSThe first step when buying any cable is to deter-mine the specific requirements of the project

2being considered. These requirements can rangefrom routine cable purchases for use in small-ca-pacity, single-phase extensions to specialized ca-bles for substation feeder exits, underwaterinstallations, or other unusual applications.Appendix E contains sample specifications for

primary cable. Appendix E addresses cables withboth EPR and TR-XLPE insulation. These specifi-cations incorporate many of the features that havebeen discussed and recommended in this man-ual. Appendix E shows features to include inspecifications for the purchase of single-conduc-tor, medium-voltage cable suitable for rural sys-tems. These specifications are compatible with,and in some cases exceed, the requirements ofpending RUS Bulletin 1728F-U1. Because theseare general specifications, they are particularlyoriented toward the routine cable purchase.These specifications may not include special fea-tures needed in a particular project. Therefore,the engineer must closely review these specifica-tions and change them as needed to meet anyunusual requirements of a particular project.Appendix C is a sample specification for sec-

ondary single-conductor and triplex cables. Threetypes of insulation are included: standard cross-linked polyethylene, ruggedized cross-linked poly-ethylene, and self-sealing insulated cables. Be-cause many secondary cable failures are causedby insulation cuts during installation, thesetougher insulations are required for reliability. Theuse of ruggedized secondary cable is recommend-ed. Self-sealing secondary cables contain a viscousmaterial between the outer layer of conductorstrands and the inner surface of the insulation.When the insulation is disrupted, the viscous in-sulating material flows into the cut and restoresthe integrity of the insulation. This stops the en-trance of moisture into the cable and arrests theprogress of the typical secondary cable failure.

TYPICAL SPECIAL REQUIREMENTSThere are certain areas in which purchaserscommonly change the specifications to meettheir particular needs.

Neutral SizeOne item that affects both the initial and the op-erating costs of an underground cable is the con-centric neutral conductivity. If the neutral selected

CableSpecification and Purchasing


for three-phase installations is too large, boththe initial cost and the circulating current losseswill be higher. However, on single-phase instal-lations, a larger concentric neutral is needed tocarry the neutral return current that may be nearthe magnitudes of the current in the energizedconductor. On single-phase installations, a re-duced neutral capacity could produce higherneutral-to-earth voltages and higher losses be-cause of the lower conductivity of the neutralconductor. Conceivably, the reduced-capacityneutral could even be thermally overloaded asthe cable approaches normal rated capacity.For these reasons, RUS requires a full-capacity

neutral in single-phase installations and allows aone-third (or greater) capacity concentric neutralon three-phase cable installations. This approachensures that there will be concentric neutral con-ductivity at least equal to the phase conductorconductivity in both single-phase and three-phase installations. The cooperative engineershould consider the typical use of the cable thatis being bought when deciding whether to usefull-capacity or reduced-capacity neutrals.

LengthEach purchaser will have different requirementsfor the length of cable on reels to use on routineinstallations. Requirements will vary with terrain,the type of equipment used to install cables, andthe typical distance between termination points.The cables should be bought in the longestlengths practical for the field crews to use so asto leave less scrap at the reel ends. Constrainingfactors will be the width and diameter of reelsthat the cable transport and installation equip-ment can accommodate.The cooperative engineer must also consider

the weight of the full reel when deciding on thestandard reel size. As with all other aspects, it ishelpful to select the same maximum reel sizesthat other cooperatives choose, especially ifthere is a group purchase arrangement. Doingso makes stocking easier for manufacturers anddistributors and consequently reduces the costfor the cooperative.

Cold Weather BendingUtilities operating underground systems in coldclimates have experienced a variety of flexibility

2problems with cables caused by the low temper-atures. To lessen these problems, the specifiercan insert a section requiring a cold bend quali-fication test. This test will indicate the probabilitythe cable will fail during bending or movementat low temperatures. It is not a measure of cableflexibility. In most cases where the cable operat-ing temperature is always above -17°C (0°F),cable bending problems are not significant.

Feeder Cable ShieldingSection 4 of this manual shows that high-capac-ity three-phase cable installations incur muchhigher losses when high-conductivity concentricneutrals are used. Induced currents that circulatebetween the neutrals of the three phases causethese losses. Lower conductivity neutral/shieldarrangements reduce these losses. Such arrange-ments not only can reduce the economic loss as-sociated with circulating currents, but also canincrease cable ampacity by cutting the amountof heat generated in the neutral/shield. Substa-tion exits or other large feeders generally havebetter load balance with lower neutral currents.Therefore, reduced concentric neutrals will haveadequate thermal capacity, especially if they aresupplemented by a separate neutral conductor.Where a high-capacity feeder is being installed,the engineer should give particular attention tothe size of the neutral and/or shield specified onthe cable.The engineer must also check the magnitude

and duration of fault currents on the system whenselecting a particular neutral/shield arrangement.Fault current duration is usually not a problemon 200-amp-class single-phase circuits becausefull-capacity neutrals are used and circuit reclos-ing is not a factor. However, the other extreme issubstation feeder exit cables where there is a de-sire to reduce neutral capacity to minimize circu-lating current losses and increase ampacity. Inthese locations, the fault currents are higher,overcurrent protective devices operate moreslowly, and reclosing is often used. All these ele-ments contribute to higher neutral/shield tem-peratures under cable fault conditions. The neu-tral/shield component of underground substationfeeder exit cables and express feeders must alsocarry fault currents for all down-line faults. Anadditional neutral conductor located in the same

76 – Sect ion 2

cable purchases to review factory production andtesting procedures. To be effective, an individualfamiliar with cable production and testing meth-ods must be present. Because the expense of thisobservation is essentially the same for large orsmall orders, large orders greatly reduce the incre-mental unit cost for observation. Moreover, withgroup purchasing, there is a greater chance thata staff engineer from one member of the groupwill have (or be able to develop) the expertisenecessary to effectively perform this function.Group purchasing and larger orders will al-

ways lead to a lower unit price. Because all thecable bought under a group plan will be accord-ing to a single specification and of the sameconstruction, the manufacturer can achieveeconomies through the following:

• Volume purchases of required material;• Longer, more efficient runs in wire drawingoperation;

• Longer, more efficient runs in cable extrusionoperation; and

• Wider distribution of fixed costs associatedwith a single order.

Group purchasing of large cable quantities hasa minimum effect on delivery practices. Manufac-turers will usually ship parts of the larger order todestinations specified by group members at noextra cost. In some cases, groups have negotiatedwarehousing arrangements with manufacturersfor release of cable on a designated schedulethroughout a year. This arrangement reduces thecash flow burden on the cooperative. It alsogives the manufacturer additional flexibility byallowing the major production runs to be sched-uled at more convenient times.Another advantage to group purchasing on a

standardized specification is the feasibility ofhaving a single distribution point where thegroup maintains a cable stock. The ability to re-ceive large orders coupled with reduced ware-house space requirements at the individualgroup members’ sites may make this approachreasonable in some cases. This option is particu-larly attractive when group purchase and stock-ing of other utility materials is also practiced.

2trench or conduit with the insulated cables cansupplement this capability. The engineer shouldpay particular attention to this set of conditionswhen selecting a reduced neutral size.

CABLE PURCHASING PRACTICESVendor PrequalificationBecause cable is one of the keys to a reliableand cost-effective underground distribution sys-tem and some types of cable defects are not ob-vious at the time of manufacture and will berecognized only years later, all cable needs to bemanufactured by reliable producers. It is in thecooperative’s best interest to review the qualifi-cations of vendors and select those that have aproven capability to produce a high-quality in-sulated conductor.Prequalification of vendors ensures that all

parties quoting on a cable order have a provenability to produce a high-quality cable meeting aparticular specification. Prequalification avoidssituations in which a vendor with questionablequalifications submits an unrealistically low price.Under these circumstances, the utility is typicallyrequired to honor the bid, which may lead toadditional long-term cost through prematurecable failure. It is only logical that if most of theutility industry is carefully prequalifying vendors,those found unqualified by others will havelower prices and better lead times because oflower demand for their products. This possibilitymakes it even more important to participate inan effective vendor prequalification program.

Group PurchaseOne way to simultaneously improve cable pricesand quality is to engage in group purchasing ofcable. This practice has several advantages toboth the vendor and the cooperative.Larger quantities (more than 50,000 feet) often

lead to better overall quality control. During theinitial part of a cable manufacturing run, largerorders mean that the front and tail ends of a par-ticular run can be scrapped. This additional costfor nonqualifying material is then spread over alarger order, thereby reducing the unit price.Active quality control is an important part of

any utility purchasing program. This quality con-trol should include factory visits during major


After a cooperative has analyzed its cable needs,written a comprehensive specification, and fol-lowed good purchasing procedures, one criticalstep remains before installation can begin. Thisstep is the acceptance and inspection of thecable delivered by the manufacturer. Cable ac-ceptance involves several simple and inexpen-sive steps that can yield big dividends. Thecooperative engineer must follow these steps tomake sure that a quality product is delivered toinstallation crews.

STEP 1. VISUALLY INSPECT FOR SHIPMENT DAMAGEVisually inspect cable reels for any damage thatmay have occurred in transit. Signs of possibledamage include impressions or nicks on the out-side layer of cable or the reel lagging. If possi-ble, this inspection should take place while reelsare still on the delivery vehicle.

STEP 2. CHECK TAGSVisually check each reel to determine that it hasproper tags and labels as described in the speci-fications. Make sure that information on the reeltags agrees with purchase-order information. Forexample, be sure that wire size, insulation thick-ness, neutral configuration, and jacket descrip-tion all conform to the specifications andpurchase order. Cable length should fall withinthe bounds described by the purchase order. Ifcable was ordered cut to specific lengths, theengineer should check the tag and sequentialjacket markings (if available) to be sure thatenough length is available for the required run.

2STEP 3. CHECK DIMENSIONAL TOLERANCEMake a simple measurement of basic cable di-mensions on one reel of each cable size in ashipment to confirm that labeling is correct.Measure these dimensions:

• Conductor size and stranding,• Insulation thickness,• Concentric neutral wire size and number ofstrands, and

• Jacket thickness.

Section 11, Cable Testing, gives further infor-mation on allowable dimensional tolerances.

STEP 4. CONDUCT CABLE ACCEPTANCE TESTINGOnce on each order or once for each 50,000 feetof cable, the cooperative should conduct a com-plete set of dimensional and electrical perfor-mance tests on the cable to make sure itcomplies with the purchase specifications andreferenced industry standards. These tests in-clude the following:

• Conductor shield resistivity test;• Insulation shield resistivity test;• Dimensional analysis of all components;• Microscopic examination for voids, contami-nants, and shield interface protrusions; and

• Insulation shield stripping test.

An outside laboratory will need to help withthese tests. Section 11 gives additional informa-tion on these tests.

Cable Acceptance


Cable systems are one of the most importantparts of any underground system. Special caremust be used in selecting both primary and sec-ondary cables. Some important points follow:

1. JCN cable must be used for most undergroundinstallations. Insulating jackets are preferred.

2. Aluminum central conductors are the econom-ical choice for most underground situations.

3. Solid conductors up to No. 2/0 AWG may be used to eliminate longitudinal moisturemigration.

4. All stranded conductors should have strandfilling in interstices to eliminate longitudinalmoisture migration.

5. Modern TR-XLPE or EPR cables offer relia -bility superior to that of earlier cables ofHMWPE or XLPE.

6. Vendor quality control and manufacturingcleanliness are essential to the production of reliable cable.

7. In heavily loaded three-phase circuits, re-duced neutrals will cut losses caused by cir-culating neutral currents. Reduced neutrals

78 – Sect ion 2

2will also increase circuit ampacity, particularlywhere phases are separated.

8. A comprehensive cable specification mustbe used and received materials inspected for compliance.

9. Initial cost, cost of dielectric losses, andcable life expectancy must be evaluatedwhen making purchasing decisions.

Underground System Sect ional iz ing – 79

Underground SystemSectionalizing3

GeneralSectionalizingPhilosophy

In This Section:

The final design and continuous reliable perfor-mance of an electrical distribution system dependon many engineering elements. Protective devicecoordination, overcurrent protection, overvoltageprotection, voltage regulation, and service conti-nuity are just a few of the elements that are incor-porated. This section addresses the coordinationof overcurrent protective devices in undergrounddistribution systems and the coordination of theseprotective devices with protective devices on in-terconnected overhead portions of the system.This section is not intended to provide a com-prehensive procedure for planning and operatinga protection program. Furthermore, the procedurefor calculating system fault current is beyond thescope of this section. An excellent reference fordesigning protection systems and calculatingfaults is Electrical Distribution System Protectionby Cooper Power Systems (1990). Many excel-lent computer programs are also available forfault current calculation.

PURPOSE OF SECTIONALIZINGLimit Magnitude of Damage and InjuryShort-circuit currents subject a system to bothmechanical and thermal stress. Mechanical stressbegins at the same time as the initiation of the

fault current and is at its maximum level duringthe first few cycles when the asymmetrical faultis at a maximum. The ability of system compo-nents to withstand mechanical stress is mainly afunction of design. Where the maximum avail-able fault exceeds the withstand capability ofthe system component, the only solutions arethe following:

• Replace the component with a heavierduty unit,

• Modify the circuit configuration to reducethe maximum available fault, or

• Use current-limiting protective devices toreduce the let-through current.

Thermal stress is a function of the energyreleased in a system component during a faultthat results in rapid heat buildup. The magni-tude of energy involved is proportional to currentsquared multiplied by time (I2t). The traditionalapproach to reducing thermal damage is to re-duce the amount of time a fault is allowed toexist through the careful selection of protectivedevices and device settings. Where maximumfault levels are so high that the operating timeof the protective device must be reduced to an

General Sectionalizing Philosophy

Overcurrent Protection of Cable System

Effect of Inrush Current onSectionalizing Devices

Selection of UndergroundSectionalizing Equipment

Faulted Circuit Indicators


80 – Sect ion 3

impracticably short interval,then current-limiting devicescan be used to reduce the faultcurrent and the duration.

Contain Fault DamageOne objective of protectiveequipment is to limit damageat the actual fault site. It isoften impossible or impracticalto completely eliminate its oc-currence. Through the use of protective devices,fault current magnitude and fault duration arereduced. This reduces, but may not eliminate,damage to the rest of the system from through-fault currents. Thus, most damage is containedwithin the actual location of the fault.

Maximize System Reliabilityand Power QualityAdherence to the following guidelines will maxi-mize system reliability.

• Purchase system components that will with-stand maximum calculated through-faultcurrents.

• Locate and size protective devices so thesmallest possible portion of the system is de-energized for a permanent fault.

• Size protective devices so they do not perma-nently open for temporary faults. Thisguideline applies mainly to overhead portionsof a system, as faults on underground systemsare usually permanent.

Additional reliability may beachieved for critical loads byuse of an automatic transferswitching arrangement. Thesearrangements are expensiveand require two or more inde-pendent sources of power.

Aid in DeterminingFault LocationProper coordination and place-ment of protective devices willhelp system operators deter-mine a fault location. If protective devices are

coordinated properly, the faultlocation should be betweenthe device that has operatedand the next load-side device.If the maximum number ofprotective devices that canfeasibly be installed are used,the length of line between de-vices will be relatively short.This design approach will re-strict the amount of line that

must be searched for a fault. Thoughtful place-ment of devices will also help locate faults. Forexample, consider a point at which three tapsbranch off a circuit. If a fuse were placed in themain circuit just before the taps branch off, op-eration of the fuse would show that a fault hadoccurred in one of the three taps but it wouldnot show which specific tap. However, if a fusewere placed at the beginning of each of thethree branches, operation of one of the fuseswould show which of the three taps containedthe fault. Installing the additional fuses in thissituation would also improve consumer reliabil-ity by reducing the number of consumers inter-rupted by a fault.

Of course, there are practical limitations onthe number and location of devices that can beplaced on a circuit. The judicious use of fault in-dicators between protective devices will helppinpoint a fault location. The application of faultindicators is presented later in this section. Faultindicators are especially useful where a circuitmay sometimes be backfed. In this situation,

protective devices may not co-ordinate properly and morethan one device may operateduring a fault. Wisely placedfault indicators would be espe-cially useful to narrow downthe fault location.

OVERVIEW OF FAULTSThe IEEE Standard Dictionaryof Electrical and ElectronicsTerms (2000) lists severaldifferent definitions of theword fault. The first two

definitions listed are relevant here:

3Optimize reliability by

sizing equipment for

maximum faults and

using enough

protective devices.

Wise placement of

protective devices

and indicators will aid

in locating faults and

minimizing outage

size and duration.


• “A wire or cable fault is a partial or totallocal failure in the insulation or continuityof a conductor.”

• “A component fault is the physical conditionthat causes a device, a component, or an ele-ment to fail to perform in a required manner;for example, a short circuit, a broken wire, oran intermittent connection.”

All faults within these two definitions fallwithin one of two major categories: an open cir-cuit or a short circuit. An open circuit is any cir-cuit in which the normal continuity of the circuitis interrupted. The IEEE dictionary defines ashort circuit as “an abnormal connection (includ-ing an arc) of relatively low impedance, whethermade accidentally or intentionally, between twopoints of a different potential.” Within the samedefinition, there is a note that the term fault orshort-circuit fault is used to describe a short cir-cuit.

Open circuits typically do not lead to damageto the electrical system. In addition, normallyavailable protective sectionalizing devices usedon electrical distribution systems do not typicallydetect open circuits. Frequently, the word faultis associated with its short-circuit definition only,and is used interchangeably for short circuit.Throughout the rest of this section, the wordfault will be used to mean short circuit. Al-though protective relays that detect open circuitsto some degree are available (and others arecurrently being developed), they are outside thescope of this section.

Description of FaultsSome of the phenomena associated with a faultare listed below.

• Very little current flows past a fault point,leading to loss of service to loads beyondthe fault.

• Voltage at the fault and beyond decreasessignificantly. The voltage between thegeneration source and the fault decreasesproportionally to the inverse of the lineimpedance.

• Faults typically lead to current levels thatexceed the thermal rating of conductor and

3other system components, causing damagewithin a fraction of a second.

• The abnormal low-impedance path caninclude nonutility property or human beings,causing damage, injury, and even fatalities.

Causes of FaultsCauses of common mechanical failures of under-ground cables are dig-ins, rodent damage, andimproper handling and installation. This lastcause includes sharp bending of cable, excessivepulling force during installation, driving vehiclesover laid cable, walking on cable in a trench,placing or leaving rocks in a position to causefuture cable damage, and allowing nails in reelsto damage cable. Principal causes of electricalfaults to underground systems include lightning,insulation treeing, and thermal insulation failurecaused by overloading.

In addition, during single-phase faults onthree-phase circuits, the phase-to-neutral voltageon the two unfaulted phases can sometimes in-crease to a level that can approach the normalphase-to-phase voltage. This increased voltageon the unfaulted phases stresses the insulationand can lead to failure. Failure of splices and el-bows is also either electrical or mechanical fail-ure, depending on the cause.

For a comparison of the sectionalizing ofoverhead and underground systems, it is usefulto examine the many causes of faults on over-head distribution lines. Some of the more com-mon causes are:

• Lightning,• Squirrels or large birds,• Extreme weather conditions,• Tree limbs or trees falling on the lines, and• Vehicular damage.

Although the intent of this section is to focus onthe protection of underground systems, overheadlines in many instances are connected either onthe source side or, less frequently, on the load sideof underground lines. In these cases, the protectivedevices often protect mixed line sections. Also, un-derground devices on systems served by over-head feeders must coordinate with those devicesprotecting the overhead portions of the system.

82 – Sect ion 3

Symmetrical Versus Asymmetrical FaultsThe terms symmetrical currents and asymmetri-cal currents refer to the symmetry of the peaksof the current waves about the zero current line.A symmetrical current is symmetrical about thezero current line, as shown in Figure 3.1. Suchcurrent symmetry would typically be found in asystem under normal operating conditions. Dur-ing an asymmetrical current, the current wave isnot symmetrical about the zero current line andcan be completely above or below the zero line.Figure 3.2 shows a typical current curve immedi-ately before and after a fault initiation. As thecurve shows, the current is symmetrical beforethe fault initiation. Immediately after the faultinitiation, the current is asymmetrical for approx-imately the first three cycles before returning toa symmetrical waveform.

The degree of asymmetry in the current curveimmediately after the initiation of a fault de-pends on two considerations. The first is the

3

FIGURE 3.1: Symmetrical Current.

time within a cycle that the short circuit occurs.If the fault is initiated during a voltage peak,then the resulting fault current will be totallysymmetrical. If the fault is initiated near a volt-age zero, then the initial fault current will behighly asymmetrical. As the point on the voltagecurve moves from the voltage zero point to themaximum voltage point, the degree of currentasymmetry decreases accordingly.

The other consideration that affects the de-gree of asymmetry of a fault current is the reac-tance/resistance (X/R) ratio of the equivalentimpedance circuit at the fault location. A highX/R ratio means the inductance of the circuit isgreater than the resistance. The higher the X/Rratio is, the greater the asymmetry of the initialfault current is, all other conditions being con-stant. Using a standard symmetrical componentnotation, Equation 3.1 shows the X/R ratio for athree-phase fault. Equation 3.2 shows the X/Rratio for a single-phase fault. The positive se-quence impedance data (X1 and R1) and zero se-quence impedance data (X0 and R0) should beavailable from a system fault study.

Total Asymmetrical Current

DC Component

AD Component

FIGURE 3.2: Asymmetrical Short-CircuitCurrent.

Equation 3.1

where: X1 = Positive sequence reactanceR1 = Positive sequence resistance

Ratio = X1 ÷ R1XR

Three-Phase Fault

Equation 3.2

where: X1 = Positive sequence reactanceR1 = Positive sequence resistanceX0 = Zero sequence reactanceR0 = Zero sequence resistance

Ratio = [(2 × X1) + X0] ÷ [(2 × R1) + R0]XR

Single-Phase Fault


3symmetrical current interrupting rating and acorresponding maximum X/R ratio for the circuitin question. Likewise, switches and sectionaliz-ers will have a close-and-latch rating expressedas amperes symmetrical with a maximum X/R ra-tio. The asymmetrical rating is based on the rms(root mean square) value of the maximum asym-metrical fault during the first half cycle of faultcurrent. The X/R rating shows that the device isable to successfully interrupt or close into themaximum asymmetrical fault current expectedfor a system with the following:

• A maximum available fault current less thanor equal to the symmetrical current rating ofthe device, and

• An X/R ratio less than or equal to the rating ofthe device.

Where an X/R ratio is used to show the maxi-mum asymmetrical interrupting rating of a de-vice, this value is usually fairly conservative. Inother words, most distribution system X/R ratioswould be expected to be less than the rating ofthis device and fall within its capabilities. Table3.1 should be useful where devices are rated inasymmetrical currents or where devices are ratedin maximum X/R ratios and the actual X/R ratioexceeds the rated value.

X/R Ratio “Maximum RMS” Factorfor 1/2 Cycle, Mrms*

1.0 1.002

1.5 1.015

2.0 1.042

2.5 1.078

3.0 1.116

4.0 1.189

5.0 1.253

6.0 1.305

8.0 1.383

10.0 1.438

15.0 1.522

20.0 1.569

40.0 1.646

100.0 1.697

* Multiply per-phase symmetrical rms short-circuitcurrent by Mrms to obtain momentary per-phaseasymmetrical rms fault current.

TABLE 3.1: Multiplying Factors to DetermineAsymmetrical Fault Currents WhereSymmetrical Fault Currents Are Known.

EXAMPLE 3.1: Device Rated in MaximumAsymmetrical Current Capacity.

The calculated maximum symmetrical fault on a sys-tem is 8,000 amperes. The X/R ratio at this location is10 and the fuse being considered for this location hasa symmetrical interrupting rating of 8,600 amperesand an asymmetrical interrupting rating of 12,000 am-peres. The multiplying factor Mrms is 1.438 for an X/Rratio of 10.0. The maximum asymmetrical fault for thislocation is 1.438 × 8,000 amperes, or 11,504 am-peres. The maximum symmetrical fault of 8,000 in thislocation is less than the interrupting rating of 8,600amperes, and the maximum asymmetrical fault of11,504 amperes is less than the asymmetrical inter-rupting rating of 12,000 amperes; therefore, the de-vice is acceptable.

The rate at which a fault current decays fromits asymmetrical waveform to an essentially sym-metrical waveform also depends on the X/Rratio. A circuit that has a low X/R ratio (one thatis mostly resistive) will decay very quickly. A cir-cuit with a high X/R ratio (one that is highly in-ductive) will take much longer to decay.

Typical protective devices such as fuses, break-ers, and reclosers are rated in maximum sym-metrical fault-interrupting capability, althoughsome fuses may be rated for maximum asym-metrical fault-interrupting capability. In addition,they will have either a maximum asymmetricalcurrent interrupting capability or a maximum

84 – Sect ion 3

Maximum Available FaultThe maximum available fault current is used todetermine if the interrupting capacity of a deviceis adequate. The maximumfault current is also the currentmagnitude at which the coor-dination of devices is checkedfor adequate time clearance.Maximum faults should be cal-culated for both three-phasefaults and single-phase-to-ground faults. Maximum faultsare calculated using those con-ditions that will lead to the maximum availablefaults. Typical conditions are as follows:

• The maximum fault is available from the powersupplier. In this case, the power supplier isoperating its system with maximum generationand with its transmission system intercon-nected to result in a maximum available fault.

• Substation transformers and buses are inter-connected to produce the maximum availablefault. A common example is two substation

3transformers operating in parallel if such anarrangement is possible and usual.

• A bolted fault (both three-phase and phase-to-ground) is applied at each location to beevaluated. A bolted fault has zero fault resis-tance (or reactance).

The system engineer should take some pre-cautions when calculating maximum faults:

• Do not calculate maximum faults for systemconfigurations that cannot actually existbecause of operating restrictions.

• When determining the interrupting capabilityof devices, use the maximum expected fault,even if it would occur only under unusual oremergency conditions.

• When considering the coordination ofdevices, calculate the maximum fault undernormal conditions. In other words, devicesshould be coordinated under normal systemconfiguration. It may not be possible to coor-dinate devices under emergency conditions(such as when a circuit is backfed from anearby substation).

• Calculate both maximum three-phase andphase-to-ground faults. This must be done be-cause phase-to-ground faults typically exceedthree-phase faults in and near delta-to-wye-

connected substation trans-formers, whereas three-phasefaults typically exceed phase-to-ground faults further out onthe circuit. Furthermore, somedevices have different operat-ing characteristics for phase-to-ground faults than for three-phase faults. Another reasonfor calculating both types of

faults is that most systems have single-phasetaps for which only phase-to-ground faultsshould be used when devices are coordinated.When coordinating devices on vee-phase lines,calculate phase-to-phase-to-ground faults.

Minimum Available FaultThe term minimum available fault current doesnot accurately describe the desired value. Theactual minimum fault current on any circuit ap-proaches zero. For example, if a broken conductor

EXAMPLE 3.2. Device Rated for Maximum Circuit X/R Ratio.

In this application, the location being considered has a maximum available sym-metrical fault current of 2,500 amperes with an X/R ratio of 20. The device beingconsidered is a recloser with a maximum interrupting rating of 3,000 amperessymmetrical and a maximum circuit X/R ratio of 12. The Mrms factor for the cir-cuit X/R ratio of 20 is 1.569. The Mrms factor of 1.569 times the maximum sym-metrical fault current of 2,500 amperes yields a maximum asymmetrical faultcurrent for the circuit of 3,922. Although Table 3.1 does not list an X/R ratio of 12,interpolation can be used to calculate an Mrms factor, which, although not exact,will be within acceptable limits.

The Mrms value of 1.4716 × 3,000 amperes symmetrical equals an asymmetri-cal interrupting rating of 4,415 amperes. The maximum fault conditions of 2,500amperes symmetrical and 3,922 amperes asymmetrical are less than the deviceratings. Therefore, the recloser is acceptable. If the circuit’s X/R ratio had been12 or less, there would have been no need to calculate the respective asym-metrical fault current.

Equation 3.3

× (1.522 – 1.438) + 1.438 = 1.4716(12 – 10)(15 – 10)

Mrms for X/R of 12 =

Maximum available

fault current should

be used to check

interrupting ratings.


falls on dry sand or a dead, bone-dry tree, theeffective fault resistance approaches infinity,causing a fault that approaches zero amperes.However, the concept of a minimum fault cur-rent actually involves calculating the minimumfault current that can be expected during mostof the faults on a system. The variables that typi-cally affect the calculated minimum fault are thefollowing:

• Available fault current from the sourceutility or transmission system, which ismainly controlled by the amount of genera-tion online and the transmission systemand bus configuration;

• The configuration of the distribution systemand substation buses; and

• The fault resistance, which is the resistancebetween the faulted conductor and the returnpath that must be added to the known imped-ances of the source, transformers, circuit, andother system components.

Although the effects of the first two variablesshould not be discounted, they frequently eitherdo not vary significantly from the maximumfault configuration or are not available in theminimum fault configuration. The third variable(fault resistance) usually has the greatest influ-ence on the difference between the maximumand minimum faults.

Many field measurements made on utility sys-tems in the 1930s were used to develop a plot ofapparent fault resistances versus a percentage offaults at that resistance level. The results showedthat the median level of faultresistance was 25 ohms andthe average level was 35ohms. A commonly used valueof fault resistance for overheadcircuits is 40 ohms. For substa-tions of greater than 5,000-kVAbase capacity operated in the15-kV distribution class, a val-ue of 30 ohms is often used.These values are for faults thatoccur on the overhead portion of the system. Forfaults on underground systems with concentricneutrals or metallic shields, some parties recom-mend a value of zero to 10 ohms to calculate min-

imum faults, with 10 ohms giving more conserva-tive results. Where circuits are composed of inter-connected sections of underground and overhead,it may be necessary to make two sets of fault cal-culations using the underground fault resistance inone run and the overhead fault resistance in theother run. It is also important to note that siteconditions vary widely between utilities andwithin each distribution system. This variabilityshould always be considered when determiningthe system standard protection parameters.

DESIRABLE LOCATIONS FORSECTIONALIZING DEVICESBeginning of UD CableIt is normally desirable to place sectionalizingdevices at the beginning of underground cables,that is, any location where a transition from over-head to underground cable takes place or in asubstation or step-down transformer where theunderground circuit originates (see Figure 3.3).Doing so will minimize restoration time andhelp distinguish between overhead and under-ground faults.

Faults on overhead lines are usually temporaryand are best protected by reclosing devices suchas breakers or reclosers. Since faults on under-ground lines are usually permanent; they are bestprotected by nonreclosing devices such as fuses.

Of course, there are exceptions to this recom-mendation, such as where a circuit is mostlyoverhead with a short section of underground(for instance, under a river, highway, transmissionline, or airport glide path). Coordinating a fusewith in-line reclosers on the source side and the

load side of the fuse might beimpossible. In this case, re-duced protection of the under-ground line section is moredesirable than frequent opera-tion of the fuse caused by tem-porary faults on the load-sideoverhead line.To compensate for the re-

duced protection of the under-ground line section, the engi-

neer could design the system with a spare cable(or cables), install the primary cable in conduit,or both. This reduces the time needed to restoreservice in case of a failed cable.

3

Reclosing is not an

advantage on a totally

underground system,

as most faults are

permanent.

86 – Sect ion 3

3

FIGURE 3.3: Sample Distribution Circuit with Typical Locations of Sectionalizing Devices Shown.

MainSubstation

115 kV–12.5/7.2 kVGRD WYE

5 miles fromMain Substation

10 miles fromMain Substation

To Next Substation

Overhead Line

Legend

Underground Line

Breaker or Recloser

Fuse

Distribution Transformer

SwitchN.C. – Normally ClosedN.O. – Normally Open

N.O.

N.O.

N.O.

N.O.

N.O.

N.C.

N.C.N.C.


Another solution is to establish an alternatecircuit route to the area that would allow the un-derground section to be de-energized for repairor maintenance without extended loss of ser-vice. Using properly installed fault indicatorsalong with solid blade disconnects at each endof the cable will help operating personnel differ-entiate a cable fault from an overhead fault.

End of Underground Cable WhereContinued as OverheadThe general use of underground cable followedby a load-side overhead line, other than shortunderground feeder exits at substations, opensup additional sectionalizing difficulties. Opti-mum fault protection of such an arrangement isalmost impossible to achieve, mainly becauseunderground faults are usually permanent andcan cause widespread damage to cable insula-tion if not quickly and permanently interrupted.On the other hand, overhead faults are usuallytemporary. Overhead lines can also be subjectedto faults for longer periods without extensivedamage. A summary of the problems associatedwith this type of arrangement follows.

1. Underground lines are protected by fuses,single-shot sectionalizers, and other single-operation devices.

2. Overhead lines are protected by reclosers orbreakers that reclose two or three times. Thepurpose of reclosing is to test for the clear-ing of temporary faults. Reclosing is oftensuccessful in avoiding a sustained outage.When there is a permanent fault, the re-closer or breaker will lock out after the thirdor fourth interruption, or a downstream fuse(or sectionalizer) will operate to isolate thepermanent fault.

3. If a recloser or breaker is installed at the be-ginning of an overhead line that is fed by anunderground line, the underground line willbe subjected to multiple through-faults be-cause of the reclosing action of the recloseror breaker. The cumulative fault durationcould lead to thermal damage of the cableand any fuse protecting the cable. Alterna-tively, if the underground line is protectedby a fuse, then any temporary faults would

3cause a blown fuse and an unnecessary out-age and service call.

4. A recloser or breaker installed at the begin-ning of the underground line to coordinatewith the load-side recloser or breaker couldlead to extensive cable damage during faultsinternal to the cable system. There have alsobeen occurrences of self-clearing cable faultsthat have allowed reclosing devices to resetbetween arcing events, thereby substantiallyprolonging the duration of faults on thecable system and making cable damagemuch more extensive. This type of fault istypically caused by a concentric neutral thatis badly corroded or fault damaged. Thefault impedance would be quite high andmay require a significant time interval to es-tablish an arc after being extinguished.

Taps Off Main Feeders and Sub-FeedersTypically, it is desirable to install sectionalizingdevices at the beginning of taps off a mainfeeder or sub-feeder. Such devices will preventservice on the main feeder or sub-feeder frombeing interrupted if there is a fault on the tap.This is also a good location because devices canbe readily installed in the switching cabinet.

TransformersPad-mounted transformers must be fused to pro-tect the system from transformer failures andsecondary faults. It is necessary to keep fusesizes small enough to limit the energy and dura-tion of any transformer fault that does occur.Proper transformer fusing reduces the chance ofa transformer catastrophically failing.

Other LocationsWhere long underground feeders exist, it may benecessary to install in-line sectionalizing devicesat one or more locations between the beginningand end of the feeder. This is particularly thecase where several heavily loaded taps are lo-cated along the length of the feeder. A feedercable fault near the end of the feeder would in-terrupt service to only some, rather than all, ofthe taps. In-line sectionalizing is also recom-mended where the feeder is so long that themaximum fault currents at the beginning and

88 – Sect ion 3

3end of the cable differ appreciably. In this in-stance, the optimum device at the beginning ofthe cable might not operate for a fault at the end

of the cable. An in-line device should be sizedto operate for a lower fault than for the deviceat the beginning of the cable.

OvercurrentProtection ofCable System

PHASE CONDUCTOR ANDNEUTRAL PROTECTIONGeneral Effects of Faults on CableDamage of underground cable because of faultcurrents falls into two general categories. Thefirst involves burning at the fault location. Theheat produced by the arc between the phaseconductor and neutral, cable shield, or other re-turn path can damage all cables and compo-nents near the fault. The second category ofdamage is that caused by a through-fault—thatis, the fault current flowing through the cablebetween the source and the fault location. Thisthrough-fault current increases the temperatureof the phase conductor and concentric neutralor metallic shield. Although it may not damagethe conductors, the elevated temperatures gen-erated by the higher I2R losses can damagethose cable materials that contact the metallicconductors. Those materials include conductorand insulation shields, the primary insulation,

and the cable jacket (see Figure 3.4). If maxi-mum through-faults fall below the levels shownon the emergency operating temperature ratinggraphs in Appendix F, then insulation damageshould not occur.

Current PathsDuring a fault, current will always flow from thesource through the phase conductor to the faultlocation. The current can then return throughseveral paths with varying percentages of thecurrent flowing in each path. These paths caninclude the metallic shield, the concentric neutral,a separate ground wire, a metallic duct system,and earth. Where jacketed cable is involved, thefault current in the concentric neutral or metallicshield may split and flow both toward the sourceand in the opposite direction from the sourceuntil it reaches external grounding connections.

Short-Term EffectsShort-term effects of faults on cable typically in-volve obvious burn damage around the fault. Insevere faults, there may be enough thermal dam-age from through-fault current to cause failure ofsplices, elbows, transformer internal buses, andcable. Poorly made splices and other connectionsare especially susceptible to thermal damage.

Long-Term EffectsLong-term effects of faults on cable include dete-rioration of insulation, conductor and insulationshields, splices, and fittings because of overheat-ing or mechanical forces from large through-faults.The exact effects on the various components vary;however, the potential results are the same. Atsome point, one of these components may breakdown as a result of normal voltage stress or nor-mal load current, causing a fault. Another possi-bility is that, during a later fault, a componentthat was weakened during previous faults willfail because of through-fault currents, leading tofailure at another location. If cables that havebeen subjected to severe through-faults repeatedly

FIGURE 3.4: Cross Section of Cable Showing Components Subject toThrough-Fault Damage.

Locations Susceptible toOverheating Damagefrom Fault Currents

Phase Conductor

Jacket

Concentric Neutral/Metallic Shield

Insulation Shield

Strand Shield

Strand Fill

Insulation

for commonly used sizes ofTR-XLPE or EPR aluminum ca-bles. For the sample 3,000-am-pere short-circuit condition,the total clearing time of therecloser falls well below thedamage time of all the conduc-tor sizes shown.

If a more conservative approach is desired,the cables can be sized to protect against ex-ceeding their emergency operating temperaturesinstead of the higher short-circuit temperatureratings. There are several reasons for consideringthis more conservative approach. First, the cablemay have been installed in a manner that re-sulted in outside mechanical forces continuouslyacting on the cable. Examples of this would in-clude rock backfill in the trench and residualsidewall pressure in conduit sweeps.

Also, the temperature rise calculations used asthe basis for the Appendix F curves consider onlycurrent in the central conductor. Single-phasefaults through concentric neutral cable will haveheat generated by both the inner central conduc-tor and the outer concentric neutral. This will re-sult in an insulation temperature higher than cal-culated by the standard equations. The emergencyoperating (or overload) temperature for XLPE,TR-XLPE, and EPR Classes I, II, and IV insula-tions rated for 90°C normal operation is 130°C(266°F). The emergency overload temperaturefor Class III XLPE, TR-XLPE, and EPR insulationsrated for 105°C is 140°C. Figures F.5 through F.8show allowable fault current durations for theconductor to reach the 130°C limit.

Figures F.1 through F.4 contain cable damagetime-current curves on the basis of the cableshort-circuit temperature rating. This is a lessconservative approach which fully stresses thecable insulation under ideal installation conditions.When using an allowable short-circuit rating, theallowable temperature for thermoplastic (HMW-PE, etc.) cables is 150°C. Thermoset (TR-XLPE,EPR, etc.) cables with a nominal operating limitof 90°C have a maximum short circuit tempera-ture of 250°C. The more conservative approachof limiting fault durations such that conductortemperatures only reach the emergency operatingtemperature rating is recommended.


fail, all the cable may need tobe replaced.

Application of ThermalDamage Curvefor Insulation SystemThe main effect on cablecaused by a through-fault isdamage to the conductor shield and main insu-lation from the heating of the outer surface ofthe conductor. In the process of sizing sectional-izing devices to protect cable, thermal damagecurves must be developed for the cables in useon a system. Figures F.1, F.2, F.3, and F.4 of Ap-pendix F show maximum short-circuit currentsfor insulated aluminum and copper conductorcables. The horizontal axis represents short-cir-cuit current and the vertical axis represents timelimitations. There are separate curves for differ-ent conductor sizes. Figures F.3 and F.4 arebased on TR-XLPE or EPR insulation, each ofwhich has a maximum short-circuit temperatureof 250°C. The appropriate graph should be usedto develop applicable thermal damage curvesfor the size cables being used. These curves arevery conservative; they make no allowance forheat transfer through the conductor shield andinsulation. When cable is protected with a fuseor other nonreclosing device, the fuse total clearcurve should fall to the left and below the ther-mal damage curve. When a multiple-operationdevice—such as a recloser—is used, the totaltime to which a cable is subjected to a faultshould fall below the thermal damage curve. Forexample, if a 70-ampere Type “L” four-shot(2A2C) recloser is used at a maximum fault cur-rent level of 3,000 amperes, the recloser will op-erate twice with a clearing time of 0.03 secondsfor each operation and then twice again, with aclearing time of 0.07 seconds each.

The total time to which the cable will be sub-jected to the maximum fault is as follows:

3Use thermal damage

curves when sizing

protective devices.

(2 × 0.03 seconds) + (2 × 0.07 seconds)= 0.20 seconds

Figure 3.5 shows the recloser time-currentcurves plotted along with cable-damage curves

90 – Sect ion 3

3

FIGURE 3.5: Example of 70-Ampere, Type “L” Recloser Curves for Cable Protection.

6054484236

30

24

18

12

600540480420360

300

240

180

120

109876

5

4

3

2

2A & 2B

B

1.9.8.7.6

.5

.4

.3

.2

.1.09.08.07.06

.05

.04

.03

.02

.01

Current (Amperes)

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,000

30,000

40,000

50,000

6,00

07,00

08,00

09,00

010

,000

6.05.44.84.23.6

3.0

2.4

1.8

1.2

.6

3,600

3,000

2,400

1,800

1,200

60

50

40

30

20

#2

#1

1/02/03/04/0250

350

500

750

A

Aluminum/XLPE/EPRShort-Circuit Temperature Rating

Type LRecloser

Time(Cycles,60-HertzBasis)

Time(Seconds)

Neutral ProtectionWhen a concentric neutral is full size or equiva-lent to the phase conductor in ampacity or whenthe concentric neutral is a reduced-size neutral

but multiple phases have neutrals operating inparallel, it is usually not necessary to review theprotection of the neutral. Where a jacketed reducedconcentric neutral, tape shield, or longitudinally


3corrugated shield is used, thesystem engineer should furtherreview the effects of a through-fault on the neutral and thematerials in contact with theconcentric neutral or shield.The through-fault capability

of connections in the neutralpath should also be examined.In those instances in which aseparate ground wire is runparallel to the insulated cables,

the current in the concentric neutrals or shieldsis typically negligible. The only portion of theconcentric neutral or shield that is subject tothermal damage is that portion between a faultand the nearest ground point in a jacketed sys-tem. Where the reduced concentric neutral orshield is jacketed and carries the majority of thereturn fault current for a phase-to-ground fault,the formulas and procedures in the following ta-bles and equations should be applied.

Although several other metals are sometimesemployed as sheath/shield material (see Tables3.5 and 3.6), copper is by far the most com-monly used. Equation 3.3 gives the minimum ef-fective cross-sectional area of metallic shieldrequired for a given fault time. Table 3.2 showsthe corresponding formulas for calculating theeffective cross-sectional area of various types ofsheaths/shields. Table 3.3 shows the approxi-mate normal operating temperature of the shieldfor various steady-state conductor operating tem-peratures for cables rated five through 69 kV.

Table 3.4 shows the maximum allowable tran-sient temperatures for shields in contact withvarious materials.

Tables 3.5 and 3.6 give the M values for usein Equation 3.3. As shown by the tables, the Mvalues are constants and depend on the shieldmaterial, the normal operating temperature ofthe shield, and the maximum allowable transienttemperature of the shield. These tables are veryconservative; no allowance is made for heat trans-fer through the jacket or through the insulationsemiconducting shield and the main insulation.

Heating of the

neutral may be a

limiting factor where

the neutral is less

than full size or the

cable is jacketed.

Equation 3.3

where: A = Metallic shield cross-sectionalarea, in circular mils

I = Short-circuit current in shield,in amperes

t = Time of short circuit, in secondsM = Constant; see Tables 3.5 and 3.6

A =I tM

Formula for Calculating AType of Shield (See Notes 1 and 2)

1. Wires applied either helically, as a braid or nds2

serving, or longitudinally with corrugations

2. Helically applied tape, not overlapped 1.27 nwb

3. Helically applied flat tape, overlapped (See Note 3)

4. Corrugated tape, longitudinally applied 1.27 [π (dis + 50) + B] b

Note 1. Meaning of SymbolsA = Effective cross-sectional area of shieldB = L.C. tape overlap, in mils (usually 375)b = Thickness of tape, in milsdis = Diameter over semiconducting insulation shield, in milsdm = Mean diameter of shield, in milsds = Diameter of wires, in milsn = Number of serving or braid wires or tapesL = Overlap of tape, percentagew = Width of tape, in mils

Note 2. The effective area of composite shields is the sum of the effective areas of thecomponents. For example: The effective area of a composite shield consistingof a helically applied tape and a wire serving is the sum of the areas calculatedfrom formula 2 (or 3) and formula 1.

Note 3. The effective area of thin, helically applied overlapped tapes depends also onthe degree of electrical contact resistance of the overlaps. Formula 3 may beused to calculate the effective cross-sectional area of the shield for new cable.An increase in contact resistance may occur after cable installation during serviceexposed to moisture and heat. Under these conditions, the contact resistancemay approach infinity where formula 2 would apply.

TABLE 3.2: Effective Cross-Sectional Area of Shield. Adapted fromOkonite Company, Engineering Data for Copper and AluminumConductor Electrical Cables, 1998.

4bdm

1002(100– L)

92 – Sect ion 3

3Shield or Sheath Temperature °C at Conductor Temperature

Rated Voltage (kV) 105 100 95 90 85 80 75 70 65

5 100 95 90 85 80 75 70 65 60

15 100 95 90 85 80 75 70 65 60

25 100 95 90 85 80 75 70 65 60

35 95 90 85 80 75 70 65 60 55

46 95 90 85 80 75 70 65 60 55

69 90 85 80 75 70 65 60 55 50

Note. The maximum conductor temperature should not exceed the normal temperature rating of the insulation used.

TABLE 3.3: Values of T1, Approximate Shield Operating Temperature, °C, at Various ConductorTemperatures. Source: Aluminum Electrical Conductor Handbook, 1989.

Shield Operating Temperature (T1), °C

Shield Material 100 95 90 85 80 75 70 68 60 55 50

Aluminum 0.039 0.040 0.041 0.042 0.043 0.044 0.045 0.046 0.047 0.048 0.049

Copper 0.059 0.061 0.062 0.063 0.065 0.066 0.068 0.070 0.071 0.073 0.074

TABLE 3.5: Values of M for the Limiting Condition Where T2 = 200°C. (Thermoplastic Materials= HMWPE, LLDPE, PVC.) Source: Aluminum Electrical Conductor Handbook, 1989.

Shield Operating Temperature (T1), °C

Shield Material 100 95 90 85 80 75 70 68 60 55 50

Aluminum 0.057 0.057 0.058 0.059 0.060 0.060 0.061 0.062 0.063 0.063 0.064

Copper 0.087 0.087 0.088 0.089 0.091 0.091 0.092 0.093 0.094 0.096 0.097

TABLE 3.6: Values of M for the Limiting Condition Where T2 = 350°C. (Thermosetting Materials= XLPE, EPR.) Source: Aluminum Electrical Conductor Handbook, 1989.

Cable Material in Contact With Shield T2, °C/°F

Cross-linked (thermoset) 350

Thermoplastic 200

Deformation-Resistant Thermoplastic 250

Note. The temperature of the shield is limited by the material in contact withit. For example, a cable having a cross-linked semiconducting shieldunder the metallic shield and a cross-linked jacket over the metallicshield will have a maximum allowable shield temperature of 350°C.With a deformation-resistant thermoplastic jacket, it will be 250°C.

TABLE 3.4: Values of T2, Maximum Allowable ShieldTransient Temperature, °C. Source: Aluminum ElectricalConductor Handbook, 1989.


3Determine the size copper wire shield required to carry a fault current of 10,000 amperes for 10 cycles for a15-kV XLPE cable having an XLPE insulation shield and a deformation-resistant thermoplastic overall jacket.

EXAMPLE 3.3: Determine Minimum Shield Size for Known Through-Fault Current.

STEP 1. Determine the approximate shield operating temperature for 90°Cconductor temperature (which is the maximum temperature fornormal operation of XLPE-insulated cables). From Table 3.3,

STEP 2. Determine the maximum allowable shield transient temperature forthe cable materials in contact with the shield, which in this case isdeformation-resistant thermoplastic. From Table 3.4,

STEP 3. Determine the M value for a copper shield with T1 equal to 85°C andT2 equal to 200°C. From Table 3.5,

From Table 3.6,

Interpolation of these values for M yields M where T2 = 250°C:

STEP 4. Calculate the required shield cross section for a fault duration of 10cycles (0.167 seconds). Applying Equation 3.3,

Number of 14 AWG wires =56,758 ÷ 4,110 = 13.8 (Use 14)

T1 = 85°C

T2 = 250°C

M = 0.063 where T2 = 200°C

M = 0.089 where T2 = 350°C

M = × (0.089 – 0.063) + 0.063

M = (0.3333) × (0.026) + 0.063

M = 0.072

250 – 200350 – 200

A = = 56,758 circular mils10,000 0.167

0.072

STEP 5. Determine the number and size of the wires necessary to equal orexceed 56,758 circular mils. Table 3.2 shows that the effective cross-sectional area of a wire shield is equal to nds

2, or the number of wiresmultiplied by the circular mil area of each wire. The number requiredfor any specific wire size is simply the total cross section calculated inStep 4 divided by the individual wire circular mil area and rounded upto the nearest whole number:

Similarly, Equation 3.3 may determine the number of any other wire size.

94 – Sect ion 3

Standard PracticesMost fuses begin to melt at approximately twicetheir continuous rating and series coil-operatedoil circuit reclosers also tend to trip at approxi-mately twice their continuous rating. For thesetypes of devices, it is typical to match the con-tinuous rating of the recloser or fuse to the con-tinuous rating of the cable. For electronicallycontrolled reclosers or relayed circuit breakers,the equivalent continuous rating would be aboutone-half the trip rating. This general rule wouldnot be used in the following situations:

• Where the maximum load expected on thecable is much less than the capacity of thecable, the protecting device can be reduced insize, improving protection of the cable as longas other coordination criteria can still be met.

• Where emergency overloads of the cable canbe routinely expected, the fuse characteristicsshould be reviewed to make sure the over-load capability of the fuse is in line with theexpected overload on the cable.

• In the areas where the cold-load pickup issubstantially more than the maximum loadcurrent or where the duration of the cold-loadpickup is long, it may be necessary to increasefuse sizes on the basis of operating experience.

Whatever the situation, the fuse or device curveshould be kept below the thermal damage curveof the cable in question. This is rarely a problemexcept where a fuse might beprotecting several cables orseveral sections of decreasing-size cable. If the system engi-neer encounters such aproblem, the obvious solutionis to insert additional fuseswherever a conductor sizechange occurs.

PROTECTION AGAINST PAD-MOUNTEDTRANSFORMER TANK RUPTUREInternal Faults as Cause of RuptureOf the very small percentage of transformer tanksthat fail by rupture, most rupture because of in-ternal faults. The magnitude of fault current ishighest for a fault between the primary leads

inside a three-phase transformer or between theprimary phase lead and ground inside a single-phase transformer. The next highest fault is whenthe primary windings short; the magnitude of thisfault depends on the impedance of the windingsbetween the fault location and the primary leads.The lowest magnitude of fault occurs because ofa short in the secondary windings. The more wind-ings between the fault location and the primaryside of the transformer, the lower the fault current.

The rupture can result from the energy re-leased within the tank and the resulting pressure.The energy, which is typically measured in joules,is proportional to the magnitude of the fault cur-rent squared multiplied by the time duration ofthe fault in seconds (I2t). Because tank ruptureis usually caused by failure of the transformerwinding, the transformer will need to be dis-carded or opened for repairs. Therefore, a com-mon solution to preventing tank rupture is toplace a partial-range, current-limiting fuse underthe oil. Although operating such a current-limit-ing fuse will require opening up the transformertank to replace the fuse, this is not a problembecause the tank will have to be opened anyway.

In addition, a dry-well canister or clip-mounted,partial-range, current-limiting fuse will providethe same result. Either of these can also be fullrange. The disadvantage of using a full-range,current-limiting fuse is that it will operate forall levels of fault current and is much more ex-pensive to replace than an expulsion fuse. The

use of a bayonet fuse in se-ries with an under-oil currentlimiting fuse can overcomemany of these disadvantages,since the replaceable elementopens for low-level faults oroverloads, and the current-limiting element opens forhigh-level faults.

Philosophy and Theory of Rupture PreventionThe basic philosophy of rupture prevention is toprevent ruptures for any and all fault conditions.The consequences of a rupture are as follows:

• Release of oil and the consequent environ-mental damage,

3

Transformers can

rupture as a result of

large internal faults.


• Ejection of flaming oil and metal parts into theair surrounding the transformer with possibledamage to equipment and surroundings, and

• The possibility of transferring the fault ontothe incoming primary lines.

There are no standards for the ability of pad-mounted transformers to withstand internal pres-sure from a particular level of fault current. Gen-erally, pad-mounted transformers have a higherwithstand value than overhead transformers be-cause of the superior energy absorption capabili-ty of a rectangular tank compared with a cylin-drical tank. Tables 3.7 and 3.8 show some possi-ble fault levels that can be used as general guide-lines for the fault level at which an overhead or

3pad-mounted transformer will rupture. Equation3.4 represents an approximate formula for calcu-lating the symmetrical fault current that will re-sult in a known I2t level.

This formula was solved for selected X/R ra-tios at the transformer rupture levels shown inTable 3.7. With the results presented in Table3.7, the maximum current that overhead andpad-mounted transformers can withstand at typi-cal distribution voltage levels and selected X/Rratios was derived and is shown in Table 3.8.However, these levels are by no means an au-thoritative guide. Consult the manufacturer of theparticular brands of transformers in use on a co-operative’s system for their withstand capability.

Practical Prevention/Reduction of RupturesPressure-Relief ValvesThe pressure inside a transformer tank will in-crease because of extended periods of overloador low-level faults that are not cleared by theprotecting fuse. If unchecked, these pressurescan increase to levels high enough to severelydeform the tank and damage bushing seals. Apressure-relief valve will release these slow build-ups of pressure, thus avoiding the developmentof high internal pressures and tank damage.However, a high-level or internal fault builds thepressure too fast for the pressure-relief valve tobe effective. In these cases, the pressure-reliefvalve cannot protect the tank from damagecaused by excessive pressure.

Secondary BreakersSecondary breakers act no faster than do expul-sion fuses. In particular, the minimum clearingtime for a secondary breaker is approximately0.8 cycles, or the same as a fuse. More important,

Equation 3.4

IS = (IA2t) × (18.75 + 105 cos θ)

where: IS = Symmetrical fault current that willresult in known I2t level

IA = Known I2t level that may result indestructive transformer damage

θ = Arctan (X/R)

System Voltage Overhead Transformers Pad-Mounted Transformers

15 kV 1.2 × 105 5.0 × 105

25 kV 6.6 × 104 3.0 × 105

35 kV 5.0 × 104 1.0 × 105

TABLE 3.7: Approximate Levels of I2t (Amperes2 x Seconds) That MayResult in Destructive Transformer Failure for Internal Faults.

Overhead Transformers (X/R Ratio) Pad-Mounted Transformers (X/R Ratio)

System Voltage 2.5 5 10 20 2.5 5 10 20

15 kV 2,600 2,200 1,900 1,700 5,400 4,400 3,800 3,500

25 kV 2,000 1,600 1,400 1,300 4,200 3,400 3,000 2,700

35 kV 1,700 1,400 1,200 1,100 2,400 2,000 1,700 1,500

TABLE 3.8: Approximate Levels of Fault Current Symmetrical (Amperes) That May Result inDestructive Transformer Failure for Internal Faults.

96 – Sect ion 3

most ruptures are caused by internal faults thatwould not be cleared by secondary breakers.

Expulsion FusesInternal fuses typically have a maximum inter-rupting rating of 3,500 amperes asymmetrical forthe weak-link type of fuse rated 7.2-kV phase-to-ground. Internal fuses rated 14.4-kV phase-to-ground typically have a maximum interruptingrating of 2000 amperes asymmetrical for theweak-link type of fuse. These interrupting rat-ings vary from manufacturer to manufacturerand should be checked for the particular fuse.

Even lower interrupting ratings are typical ofthree-phase transformers, where phase-to-phasefaults may occur. Three-phase 25-kV transform-ers with internal weak-link expulsion fuses mayhave an asymmetrical interrupting rating as lowas 600 amperes. Where the maximum availablefault level exceeds the rating of the fuse, an ex-ternal expulsion fuse withgreater interrupting rating or afull-range current-limiting fuseshould be installed in serieswith the internal weak link.As with all fuses, the maxi-mum clearing time for faultswithin the interrupting ratingof the fuse is 0.8 of a cycle. Ifthe maximum I2t let-throughcurrent as read from Table 3.8 or calculatedfrom Equation 3.4 is less than the I2t requiredto rupture the transformer, then an expulsionfuse could prevent tank rupture. It is understoodthat the external fuse must be capable of inter-

3rupting the maximum available fault current.

A common cause of tank rupture is degenera-tion of oil into combustible gases as the result ofa sustained secondary fault that eventually causesan internal expulsion fuse to operate. The fuseignites the combustible mixture and a violenttank rupture can result. Because this type of fail-ure occurs when an expulsion fuse ignites thegas mixture, the use of current-limiting fuses andpressure-relief valves (to vent gas as it is gener-ated) will help reduce this type of violent failure.

Current-Limiting FusesCurrent-limiting fuses are nonexpulsion fusesand generally have a maximum interrupting rat-ing of about 10,000 to 50,000 amperes symmetri-cal current. The maximum interrupting ratingvaries depending on the manufacturer, model,and size of the fuse. On the majority of under-ground systems, a current-limiting fuse capable

of interrupting maximum faultcurrents at all or almost alllocations should be available.Be sure that the maximumload current is less than thecontinuous current rating ofthe largest current-limiting fuseavailable.Manufacturers of current-

limiting fuses have availablegraphs or tables indicating the maximum I2tlet-through. To protect against tank rupture,the maximum total clearing I2t of the fuse mustbe less than the I2t withstand capability of theprotected transformer.

Current-limiting

fuses can protect

against tank rupture.

Effect of InrushCurrent onSectionalizingDevices

TRANSFORMER MAGNETIZINGINRUSH CURRENTSWhen a transformer is first energized, the onlymagnetic field in the transformer is that causedby any residual flux. For a very short time afterthe transformer is first energized, the currentflow will be relatively large until the steady-stateflux level is reached. The size of this magnetiz-ing inrush current depends partially on theresidual flux in the core and the impedance ofthe source. Also controlling the size of the mag-netizing inrush current is the point on the volt-

age curve of the source at the time the trans-former is energized. If the transformer is ener-gized when the supply voltage is zero, theinrush current will be at a maximum value ifthere is no residual flux within the core. If thetransformer is energized when the supply volt-age is at a maximum level, the inrush currentwill be zero.

Estimating Magnetizing Inrush Current LevelCalculating the maximum available inrush cur-rent for a particular transformer is not feasible.


These calculations require detailed design datathat are not usually available for the transformerin question. There are many rules of thumb fortransformer inrush current levels. Most of theseuse 0.1 second as the maximum duration forwhich the inrush current will flow before dyingout. One rule of thumb uses12 times the transformer base-rated full-load current fortransformers greater than 3MVA in size. For transformersless than or equal to 3 MVA insize, the maximum magnetiz-ing inrush current is generallyconsidered to be eight timesthe base-rated full-load cur-rent. The 3-MVA level used inthis rule of thumb is the three-phase MVA capacity of the transformer or ofthe transformer bank if three single-phasetransformers are used.

This magnetizing inrush current is shown ona time-current coordination curve as a singlepoint on the 0.1-second axis at the appropriateinrush current level. All protective deviceslocated on the source side of this transformershould have curves with all points on thecurve located either above or to the rightof the magnetizing inrush point.

Effects on DevicesThe main problem associated with magnetizinginrush current is the unnecessary operation ofprotective devices. This problem typically resultsfrom choosing devices with operation curves thatfall below and to the left of the magnetizing inrushpoint. When a coordination protection scheme isestablished, not only should devices protectingsingle transformers be reviewed for their appro-priate size and relationship to magnetizinginrush currents, but tap fuses or feeder protec-tive devices also should be investigated. This isparticularly true where these devices protectloads—such as industrial parks—that may haveseveral large transformers. These transformersappear to be one large transformer from theperspective of the protective device when adead feeder is energized. Below are some of theproblems associated with particular protectivedevices.

FusesThe main problem associated with fuses comesfrom using an undersized fuse. Using an under-sized fuse on a large pad-mounted transformeris a fairly common practice, particularly wherethe present load is much less than the capacity

of the pad-mounted trans-former and where coordina-tion with the protective deviceat the source prevents use ofthe size fuse that is normallyused for full capacity. If thefuse falls below the magnetiz-ing inrush current point, thefuse may have to be either in-creased in size or replacedwith another fuse of the samesize but a slower speed.

It is critical at this point to recheck coordina-tion of the new fuse with the source-side de-vices. If this fuse is on a large transformer bankon a rural system, this coordination is difficult.Fuses are particularly troublesome when under-sized, as the magnetizing inrush current maynot cause the fuse to operate the first few timesthe transformer is energized. However, over aperiod of time the fuse is gradually damaged,reducing the effective size of the fuse. Thisdamage can lead to the eventual failure of thefuse for no apparent reason. Current-limitingfuses are generally not affected if they are par-tial-range fuses. Full-range current-limiting fuseswould be affected if undersized to the pointthat the magnetizing inrush current falls abovethe operation curve.

BreakersThe area of concern for breakers is the instanta-neous setting. This setting must be above thecurrent level of the magnetizing inrush currentbecause the operation time of an instantaneousunit is less than 0.1 second. A clear indication ofan improperly set instantaneous level is a breakerwith a reclosing relay operating once instanta-neously when a transformer is energized andthen closing on the second operation, which is atime delay curve. If the breaker relay settings aresized so the operation curve falls above the mag-netizing inrush point, breakers typically are notaffected by the magnetizing inrush current.

3

Undersizing protective

devices can lead to

tripping because

of magnetizing

inrush current.

98 – Sect ion 3

ReclosersThe main problem with reclosers results fromthe initial fast curves being set below the mag-netizing inrush point. This problem is similar tothe one with a breaker in that a recloser will op-erate on the fast curves where a large transformeris located on the circuit and then close in andstay closed when operating on the time-delaycurves. Again, the solution is to simply set thefast curves above the magnetizing inrush point.In addition, reclosers with electronic controlsthat have instantaneous trip or lockout acces-sories must have the instantaneous current set-ting above the magnetizing inrush current level.

SectionalizersSectionalizers can be armed by magnetizing in-rush current; that is, the sectionalizer sees thehigh current level as a load-side fault, which isthen interrupted by a source-side recloser. Inother words, the normal attenuation of the mag-netizing current appears to be a recloser operationto the sectionalizer. Some of the new sectionaliz-ers are able to differentiate between a magnetiz-ing inrush current and a true fault current.

Application of Sectionalizing DevicesSizing protective devices or their curves to avoidtheir operation as the result of magnetizing inrushcurrents is usually simple. The curves should bechosen so they are located either above or to theright of the magnetizing inrush point. For exam-ple, a magnetizing inrush pointof 0.1 seconds and 5,000 am-peres simply shows that anypoint on the curve for whichthe operation level is less than5,000 amperes should begreater than 0.1 second. Anypoint on the protective devicecurve that is less than 0.1 sec-ond in operating time must have a current level ofgreater than 5,000 amperes. As cautioned earlier,several large pad-mounted transformers shouldbe treated as one transformer for those instancesin which circuit protective devices or stationfeeder breakers may be used to energize thegroup of transformers.

COLD-LOAD PICKUP CURRENTSOn a typical distribution system that has beenenergized long enough that the system hasreached a steady-state condition, not all theload-producing devices will be on at any onetime. Appliances such as air conditioners, heat-ing systems, refrigerators, and water heaters nor-mally cycle on and off. Therefore, at any instant,a percentage of these devices will be in their offcycles. For example, a circuit that has a 2,000-kWload on it may have 500 kW in continuous loadsuch as lights and 3,000 kW in cyclical devices,of which only half are energized at any one time.(Note that these values are used as an exampleand not intended to show normal values on asystem.) If this circuit is de-energized for an ex-tended period (e.g., 30 minutes) and the systemis then energized, all the cyclical loads will be inan energized state or will go to an energizedstate upon resumption of the source voltage.This energized state occurs because the parame-ters that are used to operate these devices—such as air temperature or water temperature (inthe case of a water heater)—exit the acceptablerange and, therefore, initiate operation of theapplicable device. In this example, the loadsseen upon re-energizing the circuit are 3,500kW. The load experienced by a system after theresumption of service following an extendedoutage period is the cold-load pickup. Cautionshould be taken when re-energizing a feederafter an extended outage because it may be dif-

ficult to distinguish betweencold-load pickup and an un-corrected fault.

Estimating Cold-LoadPickup CurrentsThe magnitude of cold-loadpickup varies depending onthe type of load served and

the time of year. In most areas, the cold-loadpickup during the spring and fall is less thanduring the summer or winter because many ofthe cyclical devices such as heaters or air condi-tioners do not operate during these periods.Cold-load pickup also clearly depends on thegeographical location of the utility in question.

3

Cold-load pickup

can cause protective

devices to trip.


These are rules of thumb and may vary. Thethree most important variables the operator canexpect concerning the amount of cold load tobe picked up upon service restoration are:

• length of outage,• type of load, and• weather conditions.

Unless the outage is at a time of extreme tem-perature, an outage of less than 15 minutes willnot allow enough time for most of the thermostatsto call for heating or cooling. The practice ofputting a time-delay relay on compressor startafter an outage is becoming fairly common. Thisdesign approach reduces the initial inrush uponline energization but does not reduce the 30-min-ute load requirement of Rule of Thumb 3.1. Mostcooperatives should have an idea of the cold-loadpickup on their systems based on experience.Furthermore, the cold-load pickup in a systemwill, of course, vary from one circuit to anotherdepending on the type of load on that circuit.For example, a circuit feeding an all-electrichousing development will have a higher cold-loadpickup than will a feeder into a residential neigh-borhood where the main heating methods areoil, propane, or natural gas. Also, some feederswith large loads using large motors, such as irri-gation systems or crop-drying systems, may havelesser values of cold-load pickup because thesesystems may have to be manually restarted.

3

Rule of Thumb 3.1

Where large amounts of resistive heating or air condi-tioning are in use, the cold-load pickup may be esti-mated as the following:

• Two times full load current for 30 minutes, and• Three times full load current for 30 seconds.

Effects on DevicesIn general, where the time-current curves for adevice fall below the cold-load inrush points, theprotective devices will operate for cold-loadpickup. In general, it is desirable to choose de-vices or particular curves for those devices sothe curves fall above or to the right of the cold-load inrush points. In those instances whereother restraints prevent this choice, it may benecessary to segment the system to pick up loadafter an extended outage. This segmentation isdone by opening the feeder that suffered theoutage at different points, picking up a sectionat a time starting at the end of the feeder nearestthe source, and allowing each section to remainenergized for long enough for the load to returnto its steady-state level before energizing thenext section. The effects of cold-load inrush ondifferent types of devices are addressed below.

BreakersThe breaker may operate if the cold-load pickupis large enough. Where an instantaneous relay isassociated with the breaker, it may be that acold-load pickup will trip the breaker once oninstantaneous trip with the breaker then recloseand provide service from that point on. The so-lution here is to simply increase the pickup levelof the time-delay curve on the breaker or, in thecase of an instantaneous pickup, to increase thepickup level. In some instances, it may be ac-ceptable to have an instantaneous pickup thattrips once on cold-load pickup.

ReclosersReclosers are similar to breakers in that they willtrip if the cold-load pickup points on the time-current curves are above the recloser curves. Thisis particularly true for the fast curves on the re-closer. In those instances in which the fast curvesfall below the cold-load pickup points but thetime-delay curves do not, the recloser may triponce or twice on the fast curves and then lockin. Those reclosers with electronic controls mayhave instantaneous trip devices that should beset above the cold-load pickup current level.Older, electronically controlled reclosers have anaccessory that temporarily doubles the amountof current required to trip the recloser.

In the Southeast and Southwest, the cold-loadpickup during the summer is quite significantbecause of the air-conditioning load. In northernstates, the cold-load pickup during the winter isprobably the most significant. However, thecold-load pickup during the winter also dependson the percentage of electric as compared withnonelectric heating systems.

100 – Sect ion 3

Newer electronic controls have a variety ofcold-load pickup adjustments. Any standardcurve can be used for the cold-load pickupcurve, along with any trip level. Other featuresthat may be available are a time delay afterwhich the curve returns to the normal curve,additional time and current adjustments to thecurve, and cold-load pickup curves for phase,ground, negative sequence, and other types ofsystem conditions.

SectionalizersThe cold-load pickup current may be sufficientto trigger the sectionalizer. In other words, thecold-load pickup current will appear as a faultto the sectionalizer. However, sectionalizers alsorequire a sharp reduction in current followingthe actuating current to register as an operationof the source-side protective device. Sectionaliz-ers also have a reset time.

In most instances, cold-load pickup currentwill, at best, cause one count on the sectional-izer; in those instances in which the current de-creases slowly, the sectionalizer may not evennote any counts. For those sectionalizers that areset for two or more operations before tripping,cold-load pickup typically will not be a problem.

FusesIf the cold-load pickup is sufficiently large, itwill blow the fuse, interrupting service to allconsumers beyond the fuse. In many instances,

3the cold-load pickup current will be insufficientto cause immediate operation of the fuse, butwill damage the fuse. Subsequent cold-loadpickups will further damage the fuse until iteventually blows either during a future cold-loadpickup or sometimes simply during times ofhigh load level.

The solution is to increase the size of the fuseor to replace the fuse with a fuse of the samesize but with a slower operating curve. How-ever, because of the long duration of cold-loadpickup currents, the slower speed fuse will gen-erally not work. When larger fuses do not coor-dinate with source-side devices and cold-loadpickup is not expected to occur very frequently,the time-current curve of the fuse can slightlyoverlap the cold-load pickup points.

Application of Sectionalizing DevicesWhere possible, the device curves should be setabove or to the right of the cold-load pickuppoints on the time-current curves. In addition,the pickup level for instantaneous relays or ac-cessories should be set above the highest cold-load pickup current level. In some instances inwhich other criteria prevent increasing thepickup level or curves, it may be acceptable forreclosers and breakers to trip on their instanta-neous or fast curves before locking in perma-nently. In those instances, it is very importantthat all cooperative personnel are aware of thatpossibility.

Selection ofUndergroundSectionalizingEquipment

REVIEW OF OVERCURRENTPROTECTION METHODSFusesThe main advantages of fuses are that they are:

• Inexpensive,• Compact,• Require little maintenance, and• Are easy to replace.

Moreover, a current-limiting fuse is the onlyreadily available device that effectively limitsfault current and, thus, reduces the destructivefailure of transformers and capacitors. The dis-advantages of fuses are as follows.

• The number of sizes and types is limited.• The total clear curves and minimum melt

curves overlap at high fault current levels forfuses with current ratings that are close toeach other.

• The maximum current-interrupting rating islimited, especially with expulsion fuses.

• Expulsion fuses produce hot gases andby-products.

• Fuses do not have any reclosing capability.• Fuses have no ability to sense low-level

ground faults.• Fuses cause “single-phasing” on three-phase

circuits.


• The types of relays that may be used to con-trol the breakers are available in a widevariety of characteristics.

• The relays (typically inverse overcurrents ona distribution circuit) may bevaried over a wide range oftime dial settings and pickuplevels to accommodate mostsystem conditions and to allowchanges as the load increasesover time. In addition to over-current functions, many of theelectronic relays provide al-most any known relay functionwithin one relay. Some ofthese functions include over/

under voltage, over/under frequency, sensi-tive earth, directional power and/or current,impedance, negative sequence, reclosing, andsync check. Other features may include faultlocation, a wide variety of metering functions,event recording, and communications. Pro-grammable logic functions can be used to de-fine the sequence of responses to almost anytype of event.

• Reclosing relays are available where breakersprotect portions of overhead line;instantaneous relays are available to providehigh-speed operation during high fault levels.

• Breakers can be purchased with maximuminterrupting capability that exceeds that avail-able in most reclosers.

• Breakers are rated for more operationsbetween maintenance than are reclosers.

• Breakers interrupt all three phasessimultaneously.

• Breakers are available with groundtrip protection.

The disadvantages of breakers are:

• They require separate relays that add to thetotal expense.

• They require much more space than fuses do.• They require an outside power source (typi-

cally a battery).• Their relays must be calibrated initially and

periodically.

3• Fuses cannot be controlled or monitored by

Supervisory Control and Data Acquisition(SCADA) systems.

In general, the main appli-cation for fuses is on radialtaps that do not require simul-taneous three-phase protectionand that are not subject to fre-quent temporary faults. Fusesparticularly lend themselves toprotecting underground cir-cuits. The inability of fuses toreclose is not a limitation onunderground circuits andtransformers, because faults onthis type of system tend to be permanent. Re-closing on this type of system simply increasesthe amount of fault damage. Using current-limit-ing fuses on pad-mounted transformers is verybeneficial when the maximum fault level isenough to cause destructive failure of the trans-former for internal faults. The primary condi-tions that limit the use of expulsion fuses atcertain locations are the following:

• Where the maximum fault current exceedsthe fault-interrupting capability of commonlyavailable expulsion fuses, and

• Where the maximum load current exceedscurrent ratings of expulsion fuses (typically200 amperes).

Another shortcoming of fuses is that theircurves do not always coordinate well with up-stream breakers or reclosers. For this reason, atcertain locations, particularly on heavily loadedfeeders, a breaker or recloser rather than fusesmay be needed to coordinate with substationbreakers or reclosers.

Circuit BreakersMost circuit breakers on underground distribu-tion systems are found in substations, althoughit is possible to install breakers on platforms onoverhead portions of the system or in metal orfiberglass enclosures. Some of the advantages ofbreakers follow.

Fuses are the most

frequently used

protective device on

an underground

system.

102 – Sect ion 3

• They are harder to operateand maintain than reclosersand, particularly, fuses.

• They are significantly moreexpensive than other avail-able devices.

ReclosersReclosers are available in bothsingle-phase and three-phaseversions. The single-phase se-ries-trip versions do not re-quire an outside power sourceand are frequently used ondistribution lines, althoughthey are seen more frequentlyon overhead than on under-ground systems. The interrupt-ing rating of most single-phase reclosers istypically less than or equal to that of most distri-bution fuses. The main advantage of a recloseris that it does reclose; however, as indicated ear-lier, this is not considered an advantage on anunderground system.

Three-phase reclosers canbe supplied with a ground-fault-sensing unit, which is anadvantage. This is a particularadvantage on circuits withlarge load where the minimumphase-to-ground fault may beon the same order of magni-tude as the maximum load current. Three-phaseelectronically controlled reclosers are also easilychangeable in pickup level and operatingcurves.

Three-phase reclosers with electronic controlare available with a wide range of SCADA acces-sories. Reclosers are usually less expensive thanbreakers and come with all controls included.The electronic reclosers do require an outsidepower source, typically 120 volts ac, although dcversions are available. Reclosers are typicallyused as a circuit protective device inside a sub-station and on main three-phase lines where thefollowing apply:

• The load current exceeds the rating oftypical fuses.

3• Three-phase protection is

desired.• Ground fault protection is

desired.• It is advantageous to use

SCADA for both control andstatus reporting of reclosers.

Where three-phase or sin-gle-phase reclosers are usedon underground circuits, it issimple to disable the reclosingfeature and have one-shot op-eration of the recloser.

SectionalizersSeveral types of sectionalizersare currently available in both

overhead versions and those that can be in-stalled in pad-mounted enclosures. For a sec-tionalizer to work properly, it must be set forone less operation than its companion recloseror breaker. In other words, for a permanent

fault, a recloser located be-tween the sectionalizer andthe source senses a fault,opens, recloses, and continuesto open and reclose until thefault is cleared or it trips for amaximum number of times(usually four) and locks out.The properly coordinated sec-

tionalizer senses a fault condition, counts eachrecloser operation, and locks out just before therecloser goes through its final close operation.The sectionalizer has, thus, isolated the fault be-yond it, allowing the recloser to successfully re-close and continue service to the rest of thesystem. On an underground system, it is desir-able to have the sectionalizer set for only oneoperation to limit the exposure of the under-ground system to through-fault damage and pos-sible safety problems. The source-side recloser isset for two or more operations to lock out. Thetotal number of operations for the recloser de-pends on whether the majority of the system isoverhead or underground.

A problem inherent in many of the older sec-tionalizers is that they tend to count magnetizing

Three-phase reclosersand breakers are usedfor the following:

Three-phaseprotection,

High load current,

High fault current,and

Ground faultprotection.

Sectionalizers are

not subject to fault-

interrupting limitations.


inrush or cold-load pickup currents as faultsand, therefore, lock out unnecessarily. Section-alizers are available that are capable of distin-guishing between faults and inrush currentssuch as magnetizing or cold load. These section-alizers use different methods for doing so. Onecriterion is to check for loss of voltage on theline. A true recloser operation de-energizes theline, allowing the voltage to fall to zero. Anothermethod is to require that the load current dropto essentially zero after the high inrush current.Again, the operation of a recloser results in zerocurrent while the recloser is open as opposed toinrush or cold-load pickup for which currentdrops to a normal level. Other features are alsoavailable in existing and new sectionalizers thatreduce nuisance tripping.

Some of the advantages of sectionalizers areas follows:

• They are less expensive than reclosersor breakers.

• They do not interrupt faults and, therefore,can be used in areas with higher availablefault currents than can fuses. (The short-time-current withstand capability of thesectionalizer, however, must be greaterthan the available fault current.)

Sectionalizers are also useful where coordina-tion between devices is tight, as they have notime-current curve. Heavily loaded taps oftencannot allow another level of coordination.

PROTECTIVE EQUIPMENT INPAD-MOUNTED ENCLOSURESFuses and SwitchesFuses and switches are com-bined here because both areoften found in the same enclo-sure, although enclosures canbe purchased with switchesonly or fuses only. In addition,fuses combined with integralload-interrupting mechanismsthat provide the dual functionof a fuse and switch in onedevice can be purchased. Pad-mounted enclo-sures with up to four or more incoming/outgoing

3circuits are readily available. Each incom-ing/outgoing circuit will pass through a solid bus,a fuse, a switch, or a combination fuse/switch.Almost any kind of circuit arrangement can beaccommodated by a switching enclosure orenclosures. See Figure 3.6.

Switches and fuse/switch combinations maybe designed for de-energized switching dutyonly or they may be equipped with an arc sup-pression device that allows opening and closingthe switches under load up to a maximum ratedcurrent level. This interrupting rating may beequal to or less than the maximum continuouscurrent rating of the switch or combinationfuse/switch. Extreme care should be taken toavoid opening or closing a switch that is carry-ing current in excess of the interrupting rating.Therefore, a design engineer should never applyan interrupting device in a location where loadwill exceed its rating.

Different types of fuses are available. Anexpulsion fuse is the most commonly availabletype. This fuse is frequently supplied with a si-lencer that eliminates or reduces venting whenthe fuse operates and also muffles any sounds.A silencer is a necessity where fault currents arerelatively high in magnitude and the resultingexhaust gases, if released within the enclosedspace of a pad-mounted compartment, can bedisastrous.

At some locations, available faults exceedthe maximum interrupting capacity of expulsionfuses. In addition, high-level faults can lead tothe disruptive failure of load-side devices suchas transformers. Full- or partial-range current-

limiting fuses are available foruse in these locations. Figure3.6 shows an assortment ofcurrent-limiting fuses that areused in pad-mountedswitchgear.Another solution for high

fault current level areas is apartial-range current-limitingfuse in conjunction with anexpulsion fuse. The expulsionfuse will operate for low- to

moderate-level faults without damaging themore expensive current-limiting fuse. Both fuses

Most protective

devices, with the

exception of breakers,

are available in

pad-mounted form.

104 – Sect ion 3

Vacuum switches are also available from somemanufacturers. These switches have contacts in avacuum bottle which increases the interruptingcapacity of the switch to handle higher ranges offault current. In addition, the duty cycle of thecontacts is greatly increased by the vacuum. In thepast, oil switches were available, but these haveessentially been replaced by vacuum switches.

The operation of all types of switches can becontrolled by several different means:

• These switches can be simply opened orclosed manually at the switch location byusing hot sticks in energized switches.

• Switches can be equipped with stored-energyoperators for local operation. These can bespring-operated or battery-operated. Stored-energy operators generally have betterswitching ratings.

• Automatic switch operators are also available.These may have current-sensing controls withor without inverse time-current curves. Whenequipped with inverse time-current curves, thesevacuum switches can then be coordinated withsource-side and load-side devices such asfuses, reclosers, and other vacuum switches.

ReclosersSingle-phase and three-phase hydraulic andthree-phase electronically controlled reclosersare available for pad-mounted enclosures. Vac-uum interrupters are typically used for increasedfault-interrupting capability and increased servicelife. Hydraulic reclosers with a limited number ofcurves and current trip levels are available, asare electronically controlled units with an exten-sive number of curves and current levels. Fault-interrupting capability varies with the currentinterrupting level of the hydraulic units and istypically 12,000 amperes or higher for the elec-tronically controlled units. Some manufacturershave overhead SF6 gas-insulated reclosers avail-able that, if not yet available for pad-mountedenclosures, may be available in the future.

SectionalizersAt least one manufacturer makes a single-phasesectionalizer that is designed for installation ina pad-mounted enclosure. This sectionalizer is

3

will operate for high-level faults, with the cur-rent-limiting fuse limiting the length and magni-tude of the fault and consequently limiting thetotal magnitude of energy expended at the fault.Sometimes the voltage withstand characteristicsof blown partial-range current limiting fusesmandate the simultaneous operation of bothfuses so that the open circuit created by the ex-pulsion fuse removes voltage from the partial-range current limiting fuse.

Another type of protective device is the elec-tronic fuse, which is actually a hybrid device. Acontrol module uses electronic circuitry to sensea fault, initiate tripping, and control the time-current characteristics of the device. An inter-rupting module interrupts the fault under thecontrol of the control module. The interruptingmodule also has current-limiting capabilities.This device is available in a range of pickup lev-els and time-current curves. Continuous currentratings up to 600 amperes and maximum sym-metrical current interrupting capability up to40,000 amperes are available. The various time-current curves available with this device canoften provide better coordination with adjacentdevices than can traditional thermal fuses. An-other advantage is that the continuous rating ofthe larger modules exceeds that available in cur-rent-limiting fuses.

FIGURE 3.6: Current Limiting Fuses for Pad-Mounted SwitchingCabinets. Courtesy of Hi-Tech Electric (T&B), 2007.


intended to work in conjunction with an upstreamrecloser or breaker and is available in one, two,or three counts before operating configuration.

A sectionalizer that is designed to differentiatebetween a true fault current and a current spikecaused by magnetizing inrush or cold-loadpickup should be chosen. Additional informa-tion on the application of sectionalizers may befound in Electrical Distribution System Protec-tion by Cooper Power Systems (1990).

Live-Front Vs. Dead-FrontTypical air-insulated, air-break pad-mountedswitchgear is available in either live-front ordead-front styles. The older, traditional live-frontstyle uses standard outdoor porcelain or poly-mer terminations, or stress cones for terminatingcable. A removable barrier just inside the doorsprovides some level of protection of personnel.Once removed, the lineman is easily exposed tothe energized parts.

Dead-front gear generally limits access to en-ergized parts by the use of modular elbow-typeterminations. Both types of switch are generallyoperated by external handles on source posi-tions, but often must be operated with insulatedsticks on fused positions. Only dead-front styleswitchgear is currently approved for new con-struction by RUS.

REMOTE OPERATION OFSECTIONALIZING EQUIPMENTReason for Remote OperationThere are several reasons to remotely operate arecloser or switch. One reason is to redistributeload. Doing so might be a response to load condi-tions on the distribution system or to remove loadfrom a transformer or other piece of equipmentthat is scheduled for maintenance or replacement.

Another reason is to isolate a faulted portionof the system. Switches can be opened to isolate

3the system section that is suspected of contain-ing the fault. The recloser or vacuum switch thatopened to isolate the fault is then closed to re-establish service to the remainder of the system.

Yet another reason is to retry a recloser orvacuum switch after a lockout caused by anovercurrent condition. On an underground system,this practice is not typically routine; however,there are circumstances in which this would beapplicable. One instance is where the under-ground circuit feeds overhead taps that are un-fused. Another instance is where the suspectedfaulted section has been removed manually andthe locked-out device is remote from the faultlocation. Another instance is when cold-loadpickup current or a switching surge is the sus-pected cause of the overcurrent condition.

Devices That Can Be Remotely OperatedDevices that can be remotely operated are elec-tronically controlled reclosers, vacuum or oilswitches, circuit breakers, and load-break-typeswitches with motor operators or other types ofpower operators. These devices must typically beordered with a remote open-and-close accessory,although such an accessory may be field-installed.

Precautions in Remote OperationThe most serious danger in remotely closing adevice is the possibility of energizing a line orequipment that is in contact with human beings.These could be cooperative personnel workingon the line or members of the general publicwho are in contact accidentally, such as throughan automobile that has damaged a pad-mountedtransformer. They could also be individuals whohave tampered with an enclosure. Another dan-ger is re-energizing a faulted line or transformerthat will lead to increased equipment damageand possible human injury.

Faulted-circuit indicators(FCIs) can be used to locate afaulted section of undergroundprimary cable. FCIs sense thepassage of a fault current anddisplay a fault condition. The

faulted line section will be lo-cated between the last indica-tor showing a fault conditionand the first indicator showinga normal condition. Field per-sonnel responding to a power

FCIs sense fault

current and display

fault conditions

Faulted-CircuitIndicators

106 – Sect ion 3

3outage can trace the status ofthe FCIs and quickly identifythe faulted line section. Theycan then isolate this line sec-tion and promptly restorepower.

Without FCIs, field person-nel must search for the fault bysectionalizing and reclosing on the fault until thefaulted line section is located. This latter methodof fault locating is time-consuming and cancause cable insulation deterioration.

When properly specified and applied, FCIsprovide the following advantages:

• Reduced outage time,• Reduced crew and equipment cost,• Reduced stress on system components,• Reduced blowing of expensive fuses,• Improved system reliability, and• Improved consumer relations.

RELIABILITY OF FAULTED-CIRCUIT INDICATORSOlder designs of FCIs havebeen plagued with operationaland application problems. As aresult, they have acquired areputation with some utilitiesas being unreliable. In re-sponse, manufacturers haveimproved the design of FCIs,and IEEE has approved a guide for testing FCIs(Standard 495). These efforts have helped toeliminate some of the operational problems. Forexample, FCIs are available with the following:

• Rugged current sensors that operate in accor-dance with IEEE Standard 495,

• An inrush restraint feature to minimize falsetrips caused by inrush currents,

• Sensitive current resets and low-voltage resetsfor use on lightly loaded circuits, and

• Sensors suitable for three-phase use wherecables are close together.

An operational problem that persists is falsetripping caused by backfeed currents. This con-dition is reviewed in the next subsection. Many

application problems can becorrected through a betterunderstanding of how anFCI works and its limitations.In addition, some manufactur-ers now supply FCIs with anarray of automatic timed resetoptions, which can greatly re-

duce or eliminate problems associated with falsetripping.

The following information gives guidelines forproper selection and application of FCIs. Whenproperly specified and applied, the FCI is quitereliable and can be a valuable fault-locating tool.

FALSE TRIPPINGAn FCI has a sensor to detect the current magni-tude present in a cable. A current that exceedsthe trip rating of an FCI causes the display toshow a faulted condition. Unfortunately, thesensor cannot distinguish between fault current,

inrush current, and backfeedcurrent. The indicator simplyresponds to any current thatexceeds its trip rating. As a re-sult, inrush and backfeed cur-rents that exceed the triprating cause false tripping.

Inrush CurrentsInrush current is a higher thannormal current that occurs

when a distribution circuit is energized. Theinrush current decays to the normal currentvalue after some time. The types of inrush cur-rents and their decay times are explained abovein the subsection Effect of Inrush Current onSectionalizing Devices.

When power is restored to a de-energizedline, an inrush current will flow through thecable. If this inrush current exceeds the triprating of an FCI, the FCI will show a fault condi-tion. Manual reset units will continue to showa fault condition until they are reset by hand.However, automatic resetting units will changeback to a “NORMAL” indication when the inrushcurrent decays to the normal load current level.In this situation, only the manual reset unitscontinue to show a false trip condition.

The FCI can be

a valuable

fault-locating tool.

Inrush and backfeed

currents that exceed

the trip rating cause

false tripping.


Two other situations produce false trippingand obscure a fault location. The first is when athree-phase recloser or breaker protects the un-derground cable. For example, a fault on phaseA trips the FCIs on phase A. The recloser orbreaker opens and interrupts power to all threephases. When the recloser recloses, phases Band C experience inrush current. If this currentexceeds the FCI trip ratings, then those FCIs willshow a “FAULT” condition. Usually the recloserlocks open before the FCIs can reset. The out-age crew now finds FCIs tripped on all threephases. Figure 3.7 illustrates this phenomenon.

The second situation is when a single-phaserecloser protects a main line with one or morelaterals. A fault on the main line trips the FCIsalong the main line. During reclosing, some ofthe laterals may experience inrush that exceeds

3Three–Phase

Recloser A-Phase Fault

B-PhaseC-Phase FCI 1

InrushCurrent FCI 2

FCI 3

FCI 4Load 1

FIGURE 3.7: Inrush Current Resulting from Operation of Three-PhaseRecloser.

FCI, normal indicationFCI, fault indication

LEGEND

Single-PhaseRecloser

Fault

FCI 1

InrushCurrent

InrushCurrent

FCI 2

FCI 3

FCI 4

FCI 5

Load 1

Load 2

FIGURE 3.8: Inrush Current Resulting from Operation of Single-PhaseRecloser.

FCI, normal indicationFCI, fault indication

LEGEND

the FCI trip rating. Again, the falsely tripped FCIsremain in “FAULT” indication following recloserlockout. Figure 3.8 illustrates this situation.

It is difficult to predict the magnitude of in-rush current. Therefore, it is difficult to choosean FCI trip rating that is greater than the un-known inrush value. For this reason, most man-ufacturers offer an inrush restraint feature ontheir FCIs. Typically, this feature disables the tripresponse for 15 to 60 cycles following the ener-gization of cable. The 15- to 60-cycle delay al-lows the inrush current to decay to its normalload value. The inrush restraint feature increasesthe cost of the FCI by about 35 to 40 percent.This additional cost is easily justified on under-ground systems that “see” the cycling action of asource-side recloser.

Backfeed CurrentsBackfeed currents continue to produce falsetrips and resets of FCIs. However, unlike inrushcurrents, backfeed currents can remain on thesystem for long durations. Therefore, a time-delay feature will not alleviate the problem. Toaddress this situation, the cooperative engineerneeds to be aware of situations that likely pro-duce backfeed currents.

Backfeed currents can occur on three-phasecircuits when a single-phase fault is cleared by asingle-phase protective device. For example, afuse will clear a cable fault on one phase whilethe other two phases remain energized. Anyload-side capacitors connected to the faultedphase may discharge into the fault. If the circuitimpedance is low enough, this discharge currentcould be large enough to trip FCIs located be-tween the fault and the capacitor bank.

More common backfeed currents result from adelta-connected motor load on a grounded-wye,grounded-wye transformer. For example, con-sider an underground system that serves severalthree-phase transformers. A cable fault in the firstcable section is cleared by a fuse. The other twophases remain energized and continue to supplypartial power to any delta-connected motorloads. The motors produce backfeed currentsalong the underground cable to the fault loca-tion. If the current level is high enough, it willfalsely trip the FCIs between the cable fault and

108 – Sect ion 3

the delta-connected motor load.All FCIs on the faulted phasemay show a “FAULT” indication.

These same backfeed cur-rents and voltages can alsoproduce false resets. Becausethe FCI trip level is usuallyhundreds of amperes and resetcurrent level is usually lessthan three amperes, false reset is a more likelyproblem than is false tripping. A feedback volt-age can also exist on the faulted phase. Thesevoltage levels can reach 50 percent of the nor-mal line-to-ground voltage for a grounded-wye,grounded-wye transformer. For grounded-wyedelta transformers, this voltage can reach 86 per-cent of the normal line-to-ground voltage. Mostlow-voltage reset units have a minimum resetvoltage that is lower than 86 percent of thenominal voltage. Therefore, these units wouldnot be suitable for grounded-wye, delta trans-formers with delta-connected loads. Becausegrounded-wye, delta-connected transformersshould not be installed on a distribution system,this situation should not occur frequently.

SELECTING A TRIP RATINGLoad and Fault Current MagnitudesThe trip rating of an FCI is the current magnitudethat causes the FCI to display a fault condition.An ideal trip rating is low enough to sense theminimum available fault current and high enoughto ignore load, inrush, and backfeed currents. Tomeet this criteria, the FCI trip rating should beclose to the available minimum fault current level.If the available fault current level is unknown,manufacturers suggest a trip rating of two-and-one-half to three times the expected load current.At long distances from the substation, the availablefault current drops substantially. As a result, theavailable fault current may get close to the mag-nitude of the load current. Again, the trip ratingshould be close to the fault current magnitude.However, the margin between the trip rating andthe inrush and backfeed currents is decreased.Thus, the FCI is more susceptible to false tripping.

The accuracy of the trip rating also affects se-lection. Most FCIs have an accuracy of ±10 per-cent. For example, an FCI with a trip rating of

3

FIGURE 3.9: Trip Response for Peak-Current-Sensitive Units.

800 amperes could trip for anycurrent in the range of 720 to880 amperes. Therefore, it isimportant to select an FCI thatremains sensitive to the mini-mum fault current throughoutits range of trip ratings.Conductor size also affects

trip ratings. The FCI sensormounts around an underground cable andsenses the magnetic field produced by the flowof current. This magnetic field is a function ofthe radial distance from the conductor. Thelarger the radial distance, the weaker the mag-netic field. FCIs are typically calibrated at a spe-cific cable diameter. If the actual cable diameteris less, then the trip rating is reduced. Likewise,a large cable diameter increases the trip rating.The manufacturer should be asked to supply the

The FCI trip rating

should be close to

the available minimum

fault current level.

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01.009.008.007.006.005.004

.003

.002

.001

Current (Amperes, RMS)

100

200

200

400

600

800

1,00

01,20

01,40

0

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

Time(Seconds)


cable diameter at which the FCI is calibrated anda correction curve for other cable diameters.

Coordination with Current-Limiting FusesSome FCIs are peak-current sensitive and willoperate within two milliseconds for any currentthat exceeds the trip rating. Figure 3.9 shows theresponse time of peak-sensitive units. The peak-current devices will coordinate with all types offuses, including current-limiting fuses. Propercoordination means that the FCI will trip beforethe fuse clears the fault. If the total clear time ofthe fuse is faster than the FCI response time, theFCI will not show a fault condition.

3

FIGURE 3.10: Trip Response for 450A and 800A FCIs.

Current (Amperes)

Time(Seconds)

10 100 1,0000.001

0.01

0.1

1

1015E 30E 100E 45

0AFC

I

800A

FCI

10,000

If the FCI is not the peak-current type, its tripresponse time is a function of the current magni-tude. Figure 3.10 shows the time-current charac-teristics for this type of FCI. Note the differencein the trip response time for the two types. Forexample, look at the 800-ampere curve of Fig-ures 3.9 and 3.10. The peak-current-sensitive FCIhas a response time of two milliseconds. Theother FCI has a response time of 0.3 seconds(300 milliseconds).

These slower devices should be comparedwith the time-current curves for the source-sideprotective device. For proper coordination withlink-type fuses, the FCI curve must be to the leftof the total clear curve of the fuse at the mini-mum fault current value. For example, refer toFigure 3.10. For a minimum fault current of1,000 amperes, a 450-ampere FCI coordinateswith a 30E and a 100E fuse. The FCI should alsocoordinate with a source-side current-limitingfuse. To coordinate, the FCI must trip at the let-through peak-current level before the fuse clearsthe fault. For most current-limiting fuses, theclear time is approximately three milliseconds.As shown in Figure 3.10, a 450-ampere FCI willcoordinate with a current-limiting fuse that has alet-through current of 1,100 amperes or greater.

Adaptive-Trip FCIThe adaptive-trip FCI does not have a specifiedtrip rating. Instead of tripping at a predeterminedcurrent magnitude, this device responds to asudden increase in current followed by a loss ofcurrent. Figure 3.11 shows the increase in currentmagnitude required to set the trip mechanism.For example, consider a sensor type B shown inFigure 3.11. To set the trip mechanism, the FCImust see an increase of 130 amperes within a50-millisecond time or 100 amperes within an80-millisecond or greater time. The trip mechanismwill release and show a fault indication only ifthe line current drops to zero. If the line currentdoes not drop to zero within 60 seconds, thetrip-set condition will reset to normal. This trip-setand trip-release sequence prevents the FCI fromshowing a false trip as a result of motor startingload or cold-load pickup. Like the other types ofFCIs, the adaptive-trip FCI must be checked forcoordination with upstream protective devices.

Fuse Minimum Melt CurveLEGEND

FCI Trip Response CurveFuse Total Clear Curve

110 – Sect ion 3

After the circuit is re-ener-gized, this FCI will adjust tothe line current within 60 sec-onds. During this 60-secondperiod, the FCI is in trip re-straint. This feature helps pre-vent false trips caused byupstream reclosers. In addi-tion, the FCI continuously readjusts itself forchanges in the nominal line current.

3

FIGURE 3.11: Trip-Set Characteristics for Adaptive-Trip FCI.Courtesy of Fisher Pierce Division of Thomas & Betts.

0.010.008

0.006

0.004

0.002

0.001

0.10.08

0.06

0.04

0.02

1.8

.6

.4

.2

108

6

4

2

100M L BD

Sensor Type

80

60

40

20

Current (Amperes)10 100 1,000 10,000

Time(Seconds)

Fisher Pierce Fault IndicatorModel 1547 Adaptive TripTime Current Curves

(5A Base Current)

WHERE TO LOCATE FCISFor an exact section of faulted cable in an un-derground system to be located, an FCI must beplaced at the source end of each cable section.Most cable sections terminate in some type ofpad-mounted equipment. Because this equip-ment also provides easy access to the cable, thelocation is ideal for FCIs. The following subsec-tions show several types of underground sys-tems and the placement of FCIs.

Underground Segments of Overhead FeedersOverhead feeders may occasionally have segmentsof underground cable. These underground seg-ments are often installed to avoid overhead lineclearance problems. Some applications of under-ground segments are the following:

• Lake or river crossings,• Highway crossings,• Transmission line crossings, and• Airport glide path crossings.

Because these underground segments are partof a main feeder, they are usually not fused.Rather, a set of solid-blade disconnects is placedat each end of an underground cable section.

A set of FCIs at each cable end will enableworkers to determine if a fault has occurred onthe underground segment. The set of FCIs on thesource side will show a “FAULT” indication for afault on the underground cable or on the outgo-ing overhead feeder. The second set of FCIs onthe load side will show a “normal” indication fora fault on the underground cable and a “FAULT”indication for a fault on the overhead feeder.This arrangement is shown in Figure 3.12.

Another consideration for this application iswhether to use a three-phase FCI or three single-

phase FCIs. The three-phase FCIhas three current sensors andone display. The display showsa “FAULT” indication for a faulton any of the three phases. Thisindicator is suitable when theunderground cable is sectional-ized with single-phase devices.The single-phase sectionalizing

device will be open on the faulted phase, thusshowing which underground cable is faulted.

Locate FCIs at the

source end of each

cable section.


In contrast, a three-phase sectionalizing devicewill open on all phases, regardless of which phaseis faulted. A three-phase FCI will show a “FAULT”indication; however, it does not indicate whichphase. For this type of application, it is better touse three single-phase FCIs. Here, only the FCI onthe faulted cable will show a “FAULT” indication.

The use of three single-phase FCIs also workswell on underground circuit exits from a distribu-tion substation. In many cases, these circuit exitsare protected by a three-phase sectionalizing de-vice. If the sectionalizing device has indicators toshow the faulted phase, a set of FCIs is neededon the load end of the underground segment only.However, if the protective device does not havephase indicators, a set of FCIs must be placed ateach end of the underground segment.

Some areas may have very long segments ofunderground cable. These segments may containabove-ground sectionalizing points or groundingpoints. Placing an FCI at these locations will lo-cate the exact faulted cable section.

3

FIGURE 3.13: FCI Placement on Three-Phase Underground Feeder.

FIGURE 3.12: FCI Placement on Overhead Feeder with UndergroundSegment.

Recloser FCIs Underground Line Segment FCIs

Three-Phase Underground FeedersThe most extensive type of underground feederconnects two substations. During normal opera-tion, this feeder has an open point with eachside being fed by a different substation. In thisapplication, the FCIs are placed on the circuitexits and on either the incoming or outgoing ca-bles in each sectionalizing cabinet. Figure 3.13shows this arrangement.

Another consideration for this type of systemis the choice of a trip rating. To select a propertrip rating, the cooperative engineer must con-sider the load and fault currents during normaland alternate feeds. If possible, a trip ratingshould be selected that will respond to the faultcurrent available during normal and alternatefeeds. Another option is to use an adaptive-tripFCI. As this FCI adapts to different line currentlevels, it responds properly during normal andalternate feeds.

A third consideration is the use of a three-phase FCI or three single-phase FCIs. As coveredin the preceding subsection, a three-phase FCI issuitable only when the feeder is protected bysingle-phase sectionalizing devices. If the de-vices are three-phase, the only way to identifythe faulted phase is to use a single-phase FCI oneach cable, unless the three-phase protective de-vice has an individual target for each phase.

Substation A

FCIs

FCIs

Substation B

Switchgear 1

Switchgear 2

Switchgear 3

112 – Sect ion 3

Underground Residential SubdivisionsAn underground residential subdivision usuallyconsists of single-phase transformers and cableoperated as an open-loop system. Figure 3.14shows this system with one FCI for each trans-former. This arrangement should work properlyregardless of the location of the loop open point.

Large subdivisions can be more complicated.These subdivisions often contain multiple single-phase loops and may contain a three-phase under-ground sub-feeder. In addition to being placed ateach transformer, FCIs must also be placed in eachswitching, sectionalizing, or junction cabinet. Fig-ure 3.15 shows FCI placement in a large subdivi-sion. If SW1 and SW2 were three-phase junctioncabinets without fused taps, then FCIs must alsobe placed on each load-side cable. This arrange-ment lets field personnel open the cabinet anddetermine which phase has the faulted cable.

3

FIGURE 3.14: FCI Placement for Single-Phase Open Loop.

FIGURE 3.15: FCI Placement for Underground Subdivision with Three-Phase Source.

SwitchingCabinet

SwitchingCabinet

RiserPole

RiserPole

RiserPole

N.O.

RiserPole


N.O. Normally Open PointFCI

LEGEND

Three-Phase, Pad-Mounted TransformerSingle-Phase, Pad-Mounted Transformer

N.O. Normally Open PointFCI

LEGEND

N.O.

N.O.

N.O.

N.O.


SELECTING A RESET METHODManual ResetThe manual-reset type is the simplest and leastexpensive FCI. It typically costs half that of theautomatic-resetting types. As expected, there aretrade-offs for this reduction in cost. First, servicepersonnel must reset this FCI in the field. Anytripped indicators that service personnel misswill continue to show a “fault” indication. Dur-ing a future outage, these indicators will confusecrews and probably increase the time requiredto locate the faulted cable section. If this be-comes a common occurrence, crews will soonignore the fault indicators.

Failure to reset an FCI is more likely on anunderground than on an overhead system. Onan underground system, the FCIs are usually lo-cated inside pad-mounted enclosures. After acrew locates the faulted line section, they mustopen all enclosures located before the faultedcable section and reset each FCI. During after-hours power restoration or during inclementweather, this step may be neglected.

This device has two other limitations:

• No coordination with current-limitingfuses, and

• No remote indicator.

3Because it operates more slowly, this FCI can-

not be used on underground systems protectedby current-limiting fuses. Without remote indica-tion, crews cannot determine the indicator statuswithout opening each enclosure. FCIs are, thus,less desirable when used on an undergroundsystem placed along the front property lines. Forthese reasons, the use of manual-reset FCIs isnot recommended.

Automatic ResetFCIs are also available with automatic reset.After tripping, these devices can sense when thecable is re-energized and will then reset to a“NORMAL” indication. Because the reset is auto-matic, these devices are more likely to show cor-rect indication than is the manual-reset type. Asa result, the automatic-reset FCIs can be a morereliable fault-locating tool.

Manufacturers offer many types of automaticreset. The costs of these different types arevery similar. These types have different appli-cations based on their limitations. Each type ofautomatic reset and how it is best used is de-scribed below.

Current ResetCurrent reset is the most common type of auto-matic reset. The device uses the same sensor todetect fault and load current (see Figure 3.16).After tripping, this device resets to “NORMAL”when it detects the return of load current inthe cable. The load current must be higherthan the reset current level. The standard resetcurrent levels are three amperes, 1.5 amperes,and 0.1 ampere.

Before selecting a current-reset FCI, determinethe normal load current. On 35- and 25-kV sys-tems, the normal load current in a single-phaseresidential subdivision may be less than threeamperes. For example, a load of 30 kW on a24.9/14.4-kV system has a current of about twoamperes. An FCI with a three-ampere reset levelwould never reset.

The lower reset levels, 1.5 amperes and less,are very sensitive and can be susceptible to themagnetic fields of nearby cables. These strayfields can lead to false tripping and resetting inthe following applications:

FIGURE 3.16: Current-Reset FCI. The unit hasa flag display housed inside a clear viewingwindow. Courtesy of Fisher Pierce Divisionof Thomas & Betts.

primary to the secondary side of the transformer.As a safety feature, this sensor has a lumped re-

sistance probe and 30-kV insu-lated cable. The resistanceprobe will limit the faultcurrent if there is a primary-to-secondary insulation systemfailure.The low-voltage-reset FCI is

ideal for lightly loaded circuitswhere the load current is nothigh enough to reset a current-

reset FCI. This FCI is not affected by the magneticfields of nearby cables during reset; therefore, thisdevice would be suitable for a lightly loadedthree-phase circuit. The current sensor to detectfault current would not have to be as sensitive asa sensor that must also detect load currents of less

than three amperes to reset.The more sensitive sensors re-quire magnetic shielding tominimize the effect of nearbycables. This is described inmore detail in the CurrentReset subsection on page 113.For three-phase use, it is im-

portant to know the minimumreset voltage. This value should be high enoughto prevent a false reset caused by a feedbackvoltage. This effect is described in the BackfeedCurrents subsection earlier in this section.

114 – Sect ion 3

• Single-phase junction cabinets,• Single-phase fuse cabinets,• Three-phase junction

cabinets, and• Three-phase switchgear.

Some of these FCIs can beequipped with magnetic shield-ing to prevent this problem.

The current-reset FCIs re-quire only a current source toreset. Therefore, these devicescan be placed in all types of pad-mountedequipment and enclosures.

Low-Voltage ResetThe low-voltage-reset FCI is equipped with aprobe that connects to the secondary voltageterminal of a transformer (seeFigure 3.17). The current sen-sor has contact with the pri-mary circuit neutral. When theFCI senses the proper amountof voltage between the sec-ondary terminal and the circuitneutral, it will reset. Most unitshave reset voltages of 120 voltsor 277 volts nominal and can be used in single-phase or grounded-wye, grounded-wye three-phase transformers.

The voltage sensor will likely cross from the

3

Figure 3.17: Low-Voltage-Reset FCI. Courtesy of E.O. SchweitzerManufacturing Division of SEL.

FIGURE 3.18: High-Voltage-Reset FCI. Courtesyof Fisher Pierce Division of Thomas and Betts.

Current-reset FCIs

can be placed in all

types of pad-mounted

equipment.

The low-voltage-reset

FCI is ideal for lightly

loaded circuits.


High-Voltage ResetThe high-voltage-reset FCImounts on the capacitive testpoint of an elbow terminator(see Figure 3.18). A primaryvoltage level of five kilovoltsor greater for a period ofabout three minutes will resetthe FCI. These devices can beused only on elbow termina-tors with capacitive test points.Care must be used on thesedevices to ensure moistureprotection.

For use with three-phasesystems, these devices must bespecified with magnetic shield-ing. Without this shielding, anFCI can show a false trip or reset caused by cur-rents in nearby cables. Another concern onthree-phase systems is the chance of feedbackvoltage on the faulted phase. If this feedback

3voltage exceeds five kilovolts,an FCI will falsely reset.

Time ResetThe time-reset FCI resets to“NORMAL” after a specifiedtime, regardless of the circuitconditions (see Figure 3.19).Therefore, it is very importantto select a time period that islong enough for crews to re-spond and check the status ofthe FCIs. If the time period istoo short, the FCI can reset be-fore the faulted cable sectionis located. These units use alithium battery to keep thereset time during the power

outage and to power a flashing LED or beepingtype of fault indicator. Most batteries have a ca-pacity of 800 flashing or beeping hours during a10-year operating life. At the end of 10 years,most manufacturers recommend replacing thebattery. If the unit does not have a replaceablebattery, it must be replaced with a new unit. Be-cause these devices will not reset because offeedback voltage or currents, they can be veryhelpful in some three-phase applications.

SENSOR INSTALLATIONProper Placement on CableDuring a phase-to-ground fault, fault current flowsthrough the conductor and a portion returnsalong the neutral. In a concentric neutral cable,the resulting magnetic field of the neutral tendsto cancel the magnetic field of the conductor. Ifan FCI is installed directly over the concentricneutral, it may not detect the fault current be-cause the magnetic field is canceled or reduced.

A second problem occurs on a three-phasesystem. During a phase-to-ground fault, currentcan flow in the concentric neutral of the un-faulted phases. An FCI mounted directly over theconcentric neutral can sense this current. If thecurrent is large enough, it will falsely trip thefault indicator. Correct placement of the FCI min-imizes these problems.

Correct placement can be done in one of twoways. The first method is to train the concentricneutral conductors back over themselves on the

Time-reset devices

do not respond

to feedback voltage

or current.

Correct FCI sensor

placement is

necessary for

proper operation.

FIGURE 3.19: Time-Reset FCI. This unit isbattery powered and has an LED flashing lightdisplay. Courtesy of Fisher Pierce Division ofThomas & Betts.

116 – Sect ion 3

cable. The FCI is then installed over the portionof the cable where the neutral conductors areoverlaid. The second method is to train the neu-tral conductors to the outside of the FCI. TheFCI is placed on the cable above the concentricneutral conductors. Figures 3.20 and 3.21 illus-trate correct and incorrect FCI placement.

For a shielded cable with 5- or 10-mil tape,the impedance of the tape shield is largeenough that it carries very little fault current.Instead, the neutral will carry most of the fault

3current. Therefore, an FCI can be placed directlyover a shielded cable without adversely affectingthe operation of the FCI.

Effect of Adjacent Conductor CurrentThe FCI current sensor responds to the magneticfield that results from a fault current flowingthrough the underground cable. When under-ground cables are close together, these magneticfields can overlap. These conditions exist in three-phase pad-mounted transformers, sectionalizingcabinets, and junction cabinets. A sensor that isnot magnetically shielded can sense the mag-netic field of adjacent conductors. A fault currenton one conductor can produce a magnetic fieldstrong enough to trip the FCIs on the other twoconductors. This false indication can be avoidedby not using unshielded current sensors in three-phase, pad-mounted equipment. Three-phaseapplications require the use of shielded sensors.

A shielded sensor forms a complete magneticcircuit around the conductor to which it attaches,effectively shielding the sensor from nearbymagnetic fields. However, some closed-core sen-sors are designed to detect very low current flow,as low as 0.1 ampere. These sensors are extremelysensitive to low magnetic fields and, thus, sus-ceptible to false trips and resets. These sensorscannot be used in three-phase equipment.

IEEE Standard 495 requires a test for the effectof adjacent current-carrying conductors. The testmust verify that the indicator will continue toshow “NORMAL” when the sensor is at the man-ufacturer’s specified distance from an unshieldedcable carrying a fault current. The sensor mustnot be affected by orientation.

FAULT INDICATIONTo be of any use, an FCI must show—by avisual display, a radio frequency (RF) output,or other means—that a fault condition occurred.Figure 3.22 shows an FCI with an RF signaloutput. Figures 3.19 and 3.17, respectively,show FCIs with remote LED and visual flagdisplays.

An RF FCI eliminates the need to look for theunit. This is a definite advantage in areas wheresnow or vegetation may obscure a visual dis-play. RF FCIs are also significantly more effective

FIGURE 3.20: Correct Placement of FCI Sensor. Adapted from Yeh, 1990.

Concentric Neutral MustBe Looped Back Through

Sensor Core to CancelEffect of Current in Neutral

FIGURE 3.21: Incorrect Placement of FCI Sensor. Adapted fromYeh, 1990.


when the cable is relatively inaccessible, such asunder bridges, in subterranean vaults, or in diffi-cult terrain. Another advantageis that the fault-locatingprocess is faster becausecrews do not have to openpad-mounted equipment.

The more usual kind of in-dication is the visual display.Common types include theflag display, the LCD readout,and the LED flashing light. Aflag display and LCD readout are typicallyhoused behind a clear viewing window thatranges from one to three inches in diameter (seeFigure 3.16). In contrast, the size of the flashinglight is only ¼-inch in diameter (see Figure3.19). This size of opening is definitely easier toinstall in a manner that maintains the integrity ofthe equipment enclosure. The flashing light iseasily seen at night but can sometimes be diffi-cult to see in bright sunlight. An internal batterypowers the flashing light display.

Some FCIs have directional capability. Theseare useful in locations where fault current mightflow in either direction. One type of directional

3display that was previously used had an indica-tor arrow that pointed toward the fault. This typeof FCI provides some advantage in large subdivi-sions because crews can first check an FCI in themiddle of a cable run and trace the fault fromthere instead of from the dip pole. The direc-tional feature is also useful if cable circuits areoperating in parallel. Some models of the direc-tional FCI must be connected to a secondary-voltage bushing or an elbow test point in orderto establish the direction of fault current flow.When this type of FCI requires secondary volt-age, it is suitable for use in pad-mounted trans-formers only; extreme care must be used incorrectly connecting the secondary leads toestablish the proper polarity. There are othermodels of directional FCIs that do not requirea voltage connection.

Visual displays can be mounted on the sensoror can be supplied with a lead to allow remotemounting. To view a display that is mounted onthe sensor, outage crews must open the trans-former or switchgear, which requires unlockinga padlock and releasing the captive bolt. Thenthe cabinet must be restored to a secure condi-

tion. This process can be time-consuming, especially whenthe crew is under pressure tolocate the fault and restoreservice.

Mounting the display re-motely on the enclosure wallreduces the time spent identi-fying the faulted section ofcable. The display can thus be

viewed without opening the piece of equipment.This mounting method does require installing aviewing window on the enclosure. Most pad-mounted equipment can now be ordered withprovisions for mounting FCI remote indicators.For existing equipment, remote mounting kitsare available.

A viewing window for a flag display mustbe large enough to expose its face, usually aone- to three-inch diameter circle. A circle is cutthrough the enclosure wall. This opening is thencovered with a piece of Plexiglas®. The Plexiglasprovides some protection from impact and entryinto the enclosure. Remote mounting of the

An FCI indicates a

fault condition by

a visual display or

other signal.

FIGURE 3.22: Typical Radio Transmitter Unitto Accommodate Up to 12 FCIs. Courtesy ofE.O. Schweitzer Manufacturing Division of SEL.

118 – Sect ion 3

flashing LED is possible with a fiber optic cableand requires only a ¼-inch hole. The displaymounts directly through the hole; there is noPlexiglas cover.

Remote displays allow restoration crews totrace fault indicators faster. This reduces outagetime and improves system reliability. However, adetermined vandal could break through thePlexiglas and gain entry into pad-mountedequipment. The flashing light indicator presentsless risk of forced equipment entry. However,the cooperative engineer should investigate thedurability of this device to be sure that it is verydifficult to damage or remove. A ¼-inch hole islarge enough to probe an object into the pad-mounted enclosure. In areas subject to vandal-ism, a display mounted on the sensor or aremote flashing light display should be consid-ered. In other areas, remote displays of eithertype are beneficial.

Acoustic annunciation is another specializedtype of FCI output. This type of FCI has a bat-tery-powered speaker that emits a distinctivetone after the passage of a fault. Application ofacoustic FCIs is generally limited to locationswhere the equipment could be obstructed bysnow or vegetation, thus limiting the effective-ness of visual indicators. Acoustic indicators areusually time-reset with provisions for manualreset during circuit restoration.

Another type of FCI output is a contact suit-able for input to a distribution SCADA system.This approach might be useful in congestedareas, such as shopping centers, where there aremany fault indicators and an opportunity forcommunication circuits to connect several FCIsto a common SCADA remote terminal unit.

A final concern is that the display maintainsits state during normal handling in the field.IEEE Standard 495 requires an impact resistancetest. This test requires the display to maintain its

indication state when the transformer lid isslammed open or shut. This is particularly im-portant for indicators with mechanical flags.

OTHER CONSIDERATIONSFault Current WithstandFCIs are exposed to high fault currents. To bereliable, an FCI must continue to operate prop-erly after being exposed to these high currentlevels. The cooperative engineer should specifythat all FCIs meet the Short-Time Current Test ofIEEE Standard 495.

Maximum Continuous CurrentAn FCI must be capable of operation when ex-posed to the maximum continuous load current.Indicators with fixed pickup settings will givefalse indications if the load current exceeds theirrating. Adaptive FCIs have the ability to accom-modate increasing load currents, but, in somecases, these changes in trip characteristics mayimpair coordination with system overcurrentprotection.

Environmental RequirementsAn FCI must operate in harsh environmentsincluding direct sunlight, earth burial, andintermittent or continuous water submersion.An FCI must also operate under a varying rangeof temperatures. IEEE Standard 495 requires thatFCIs operate properly in an ambient tempera-ture range of -40 to 85°C. In addition, thisstandard requires the following design teststo ensure that FCIs will function in their harshenvironments:

• Temperature cycling test,• Water submersion test,• Outdoor weathering of plastics test,• Salt spray test, and• Immersion corrosion test.

3


1. Fault current values should be availablefrom system fault current study.

2. Sometimes the maximum interrupting ratingof a protective device is rated in asymmetri-cal amperes but only a symmetrical faultcurrent rating is available. Use Equations 3.1and 3.2 and Table 3.1 to convert fromsymmetrical to asymmetrical.

3. When minimum fault is calculated, a fault re-sistance of zero to 10 ohms for undergroundcable and 30 to 40 ohms for overhead line isrecommended. Zero ohms for undergroundand 30 ohms for overhead are less conser-vative and should be used only within therestrictions noted in the Minimum AvailableFault subsection and subject to goodengineering judgment and knowledgeof the system.

4. All load-carrying components should berated to withstand maximum through-faultcurrents on the system. If this is not possi-ble, current-limiting fuses or circuit recon-figuration should be used to limit the fault.

5. Proper location of protective devices willlimit fault damage and the number of con-sumers affected by the fault and also helplocate the fault. Recommended locationsare the following:

(a) In substations,(b) At the beginning of underground cable,(c) At transitions from underground to

overhead,(d) On taps off main feeders and

sub-feeders,(e) On transformers, and(f) Within long feeders.

6. Use the cable damage curves in Appendix Fto determine if a protective device protectsa cable against through-fault damage. Theshort-circuit curves are normally used; how-ever, the emergency overload curves can beused for a more conservative approach orwhere the cable is normally operated nearits continuous ampacity limit.

7. Where the neutral/shield is reduced in sizeor is jacketed, the temperature increase inthe shield during faults may be more criticalthan the temperature increase in the phase

3conductor. Equation 3.3 and Tables 3.2through 3.6 can be used to evaluate thetemperature increase in the concentricneutral or shield during faults.

8. Table 3.8 shows fault levels that may lead todestructive transformer failure for internalfaults. If actual withstand levels of I2t valuesare known for a particular transformer,Equation 3.4 should be used to calculate acorresponding maximum symmetrical faultlevel. Current-limiting fuses should be usedto protect against destructive transformerfailure in high-fault areas.

9. The magnetizing inrush current point fora transformer is estimated as follows:

Summary andRecommendations

Transformer Size MagnetizingThree-Phase Single-Phase Inrush Current

>3 MVA >1 MVA 12 × base-ratedfull-load currentfor 0.1 seconds

≤ 3 MVA ≤ 1 MVA 8 × base-ratedfull-load currentfor 0.1 seconds

Protective device curves should fall to theright of and above this point to preventunnecessary tripping.

10. A good rule of thumb for cold-load pickupcurrent is the following:

(a) Six times full-load current for one second,(b) Three times full-load current for up to 10

seconds, and(c) Two times full-load current for 100

seconds up to 15 minutes.

Frequently, these points may be modifiedon the basis of the type of load and localclimate. Protective device curves shouldfall to the right of and above these pointsto prevent unnecessary tripping. Thiscoordination may not always be possible.

11. Several types of protective devices areavailable for use on an undergroundsystem. Most of these are available in apad-mounted type enclosure. Several ofthese devices can be operated remotely.

Equipment Loading – 121

Equipment Loading4

Primary CableAmpacity

In This Section:

For an underground distribution system to beoperated reliably and efficiently, the two majorsystem components—cables and transformers—must be sized properly. The current rating orampacity of primary and secondary cables mustbe selected to economically serve the load overthe lifetime of the installation. To meet this re-quirement, cables must supply the load duringpeak periods without overheating and within ac-ceptable voltage limits. Pad-mounted transformer

kVA ratings must be selected to carry highly di-verse loads with peaks that may exceed thetransformer rating. Transformers must be de-signed to carry these temporary overloads whilelasting 20 years or more. By reviewing the con-ditions that affect primary and secondary cableampacity and the ability of transformers to carryoverloads for short periods, the engineer willhave the tools to design the best UD system tomeet various system requirements.

Primary Cable Ampacity

Pad-Mounted Transformer Sizing


A simple definition of ampacity is the amount ofcurrent that a cable can carry under a specificset of circumstances. When current flowsthrough a cable, losses in the form of heat aregenerated in the conductorand insulation. The ability ofthe cable to transfer this heatto the surrounding environ-ment sets the actual ampacityof the cable.

The maximum conductoroperating temperature limitsthe allowable loading of UD cable, althoughloading the cable to the maximum operatingtemperature of the insulation will not shortenits life. However, voltage regulation and flickercan limit circuit loading to a value less than the

thermal operating limit of the cable. Voltagedrop is often the deciding element in very longcable runs. For short runs and large currents,ampacity is usually the limiting element.

Maximum insulation temper-ature is not the only considera-tion for an undergroundcircuit. Soil temperaturearound direct-buried cable orconduit should also be consid-ered. If cable temperature risesto an excessive level, the sur-

rounding soil may dry out, causing a large in-crease in soil thermal resistivity. If the conditionpersists for an extended period, it can lead tothermal instability of the soil, which will causehigher cable temperatures and shorter cable life.

Ampacity = Current

Rating of Cable

122 – Sect ion 4

In light of these aspects that affect the ratingof a cable, a more exact definition of ampacitycanbe formulated. The ampacity rating of acable is the amount of current (in amperes) thatwill cause the temperature of the conductor torise from the stated ambient temperature to, butnot above, the rated operating temperature ofthe insulation under specific conditions that af-fect the rate at which heat is removed from thesurface of the cable. On the basis of this defini-tion, the basic procedure for calculating cableampacity will be explained.

A method to accurately compute ampacityunder various installation and operating condi-tions was first published in 1957 in a technicalpaper by Neher and McGrath titled “The Calcu-lation of the Temperature Rise and Load Capa-bility of Cable Systems.” This basic procedure isstill used today to calculate cable ampacity. It isused to calculate the maximum conductor tem-perature as limited by therated operating temperature ofthe insulation. The conductorcurrent required to producethe temperature change can becalculated with Equation 4.1.

4

TC= I2 RC RT

where: TC = Change in conductor temperature in degrees Celsius causedby current-produced losses (T conductor/T ambient)

RT = Effective thermal resistance between the conductor andambient soil, in °C-cm/Watt

RC = Effective electrical resistance of the conductor, inmicro-ohms per ft

I = Conductor current, in kiloamperes

I =Tconductor – Tambient

RC RT

The actual computations are quite involved,but engineers will rarely find it necessary to cal-culate ampacity ratings for the cables in their in-ventories because ampacities for a large range ofcable sizes and installation conditions have al-ready been calculated. The ICEA created Publi-cation No. P-46-426, Power Cable Ampacities,Volumes I and II, dated 1962. These tables arenow quite dated and are valuable only for theinstallation conditions and parameters theydescribe. A newer publication, ICEA P-53-426,which was issued in 1976, addressed UD-stylecables and, in particular, the effect of shieldlosses on ampacities in single-conductor cablesand temperatures in the earth surroundingburied cables and ducts.

Although these publications have served theindustry well over the years, new insulationcompounds and manufacturing processes havemade the older tables of limited use. The Insu-

lated Conductor Committee ofthe IEEE compiled more up-dated cable ampacity tablesand published IEEE Standard835-1994, which lists cablesfrom 600 volts to 500 kV, inducts, in air, and in direct-buried situations, with virtually

all combinations of single-phase, vee-phase,three-phase, and multiple circuits. An abstract ofthese tables is reproduced as Table 4.1.

Two-conductor, concentric neutral powercables consist of one insulated central conductorand one copper concentric neutral conductorapplied helically over the insulation. They areused on single-phase or three-phase primaryunderground distribution systems with operatingvoltage up to 35 kV.

If an application arises that is not covered bythese ampacity tables, IEEE 835-1994 or Appen-dix G should be consulted. Cable vendors canalso supply cable ampacity ratings for the specialinstallations. Also, PC-based ampacity programscalculate ampacities for most cable installationarrangements and types of cable. Such programsalso help to perform sensitivity analyses in whichdifferent parameters can be varied to determinetheir effect on the ampacity of the cable. Unfortu-nately, these programs are sometimes expensive

Use ampacity tables

to pick cable ratings.

The change in conductor temperature, TC, isgiven for a particular installation being consid-ered. Once RC and RT are calculated, Equation4.1 can be solved for cable ampacity:

Equation 4.1


and their purchase cannot be justified by mostcooperatives for occasional use.

CONDITIONS AFFECTING CABLE AMPACITYThe maximum ampacity of a concentric neutralUD cable depends on the ability of its surround-ing environment to dissipate the heat generatedby internal losses. Losses occur physically withinthe cable in its conductor, insulation, and neu-tral. Losses in the insulation and neutral may ormay not be negligible, depending on the type of

4

insulation and elements associated with the instal-lation of the cable. Heat flows outward from wherethe losses are generated toward the jacket. Whenheat flows through the thermal resistance of thevarious elements between the conductor and thesurrounding soil, it causes a thermal gradient.The temperature gradient, when added to theambient temperature of the soil (or air), equalsthe final conductor temperature. This conductortemperature must not exceed the operating tem-perature of the cable insulation system.

Conductor Conductors Rated 15 kV, 90°C, 100% LF

Size AWG Copper Aluminum

or kcmil Buried* In Duct* Duct in Air** Buried* In Duct* Duct in Air**

4 200 121 91 156 94 71

2 260 155 118 203 121 92

1 297 176 135 232 137 105

1/0 339 200 154 264 156 120

2/0 387 227 176 302 177 137

3/0 442 258 201 344 201 156

4/0 504 293 230 393 228 179

250 — — — 437 255 200

300 — — — 488 288 226

* Two-conductor full-concentric-neutral cable in direct burial at an ambient temperature of 25°C, 100% load factor, andsoil thermal resistivity rho-90.

** Two-conductor full-concentric-neutral cable in conduit in air at an ambient temperature of 40°C, 100% load factor,full sun, no wind.

The multiplying correction factors for load factors of 50% and 75% are as follows:

Correction Factors75% Load Factor 50% Load Factor

Cable Rating kV Buried In Duct Buried In Duct

15 1.08 1.04 1.16 1.07

Continuous loading at maximum rating may lead to moisture migration away from the cables and increased soil thermalresistivity, and a condition of thermal runaway may occur. See “Power Cable Ampacities,” ICEA Publication No. P-46-426;IEEE Publication No. S-135, Section 5, page XIII; or ICEA Publication No. P-53-426 (Reaffirmed 1982), NEMA PublicationNo. WC 50, page VI, Section E.3, and IEEE Standard 835-1994.

Adapted from ICEA S-66-524, NEMA WC 7 (12/84), page 83, and ICEA S-68-516, NEMA WC 8 (reaffirmed 1982), Part 8,page 7, and modified to 25°C ambient earth temperature by multiplying by 0.9636.

TABLE 4.1: Ampacities for Single-Phase Primary Underground Distribution Cable—XLPE,TR-XLPE, and EPR Insulated.

124 – Sect ion 4

Electrical LossesOne condition that affects cable ampacity is themagnitude of electrical losses. When a cable isenergized and current flows, losses in the formof heat are produced in the conductor and itssurrounding insulation and coverings. The rateat which the heat is removed from the cable de-termines the temperature rise within the dielec-tric and, thus, the ampacity of the cable. Electri-cal losses can be divided into two types: currentdependent and non-current dependent. Current-dependent losses are caused by current flow inthe central and concentric neutral conductors.Non-current-dependent losses are due to thepresence of the electrical field within the cabledielectric. They are a function of voltage and arepresent any time the cable is energized.

Current-dependent losses are ohmic losses inthe conductor and concentric neutral and varyas the square of the current. Losses in the cen-tral conductor represent the main heat-generat-ing component and are directly related to its acresistance. Losses in the cable concentric neutraloccur when voltage is induced on the neutralwires because of the mutual reactance between

them and the central conductor. Because safetypractices require the neutral to be grounded atmultiple points along its length, the inducedvoltage will cause current to flow in a three-phase application, adding to the total systemloss. Generally, the greater the neutral resistancefor cable sizes below 1,000 kcmil, the less thelosses will be because of the proportional de-crease in current magnitude. This effect isgraphically shown in Figure 4.1.

It is not usually necessary to calculate the re-sistance of the concentric neutral because it isexpressed as a fraction of the known conductorac resistance. For example, full and 1/3 are thetwo concentric neutral resistance values speci-fied in RUS Bulletin 1728F-U1 for primary cable.A full neutral means the neutral and phase con-ductors have the same resistance, whereas 1/3means the concentric neutral resistance is threetimes the resistance of the central conductor.

Non-current-dependent losses are caused bylosses in the dielectric and charging current loss.The dielectric loss is present any time the cableis energized; the value of the loss is proportionalto the square of the voltage. These losses are

4

FIGURE 4.1: Ratio of Shield Loss to Conductor DC Loss (Ysc ) at 90°C as a Function of ShieldResistance (Rs), 1/C 35-kV Aluminum Power Cables in Triplexed Formation. Source: ICEAPublication No. P-53-426.

0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375

FULL

1/3

1/6

1/61/6

1/3

1/3

1/31/3

FULL

FULL

FULL

FULL

0.4

0.35

0.3

0.25

0.2

0.15

0.1

.05

0

Y sc

Rs (Microohms per Foot)

1,000 kcmil750 kcmil500 kcmil350 kcmil4/0 AWG


caused by the in-phase components of voltageand current induced in the dielectric.

Charging current losses are caused by the flowof charging current and are separate from the realpower flow through the cable. Charging currentis a function of cable capacitance and is presentany time the cable is energized. Loss calculationsinvolving charging current are, therefore, doneat 100 percent loss factor. Losses are equal tothe charging current squared times the ac resis-tance of the cable. Because charging current isproportional to voltage, losses caused by it areproportional to the square of the voltage.

Although dielectric losses must be consideredwhen setting ampacity ratings for UD cables andare factored into the ampacity tables, their effectsare more pronounced at transmission voltages.

Equations to calculate con-ductor losses, dielectric loss,cable capacitance, chargingcurrent, and charging currentloss for underground cablesare found in Section 1, Equa-tions 1.1 through 1.7.

4Load Factor/Loss FactorA second element that affects cable ampacity isthe load factor/loss factor of the load. The maxi-mum temperature rise of a cable depends on theshape of the load curve and the thermal resis-tance of the heat transfer path. A cable will havea smaller temperature rise if the load varies overa 24-hour period than if the peak load was ap-plied for the whole day. The effect of a load fac-tor less than unity is recognized in ampacity andtemperature rise calculations by using loss factor.The loss factor is the ratio of the average lossesto the peak losses over a specified period. TheIEEE ampacity tables are based on loss factorsdetermined on the basis of losses for the averagemaximum load over a one-hour period. Ampac-ity tables are based on the projected load factor

of the circuit. Load factor isdefined as the ratio of the av-erage load to the peak load.

The relationship betweenload factor and loss factordepends on the shape of theload duration curve. Becauselosses vary as the square ofthe current, the value of the

loss factor can vary between the extreme limitsof load factor and load factor squared. Figure 4.2shows this relationship, with curves A and Brepresenting the theoretical limits betweenwhich the relationship can vary. Typical loadcurves for any distribution feeder will fall be-tween the two curves. The loss factor is alwaysless than the load factor except where they areboth unity. This condition occurs when there isa constant load on the cable.

The loss factor cannot be calculated directlyfrom load factor because losses are proportionalto the square of the current and the resistance,whereas the load factor depends only on thecurrent (assuming constant voltage). Note thatboth factors are related to time. Observations bymany utility engineers over the years have re-sulted in a relationship between the two valuesthat gives a reasonable value of loss factor interms of its corresponding load factor. The rela-tionship can be expressed by the empirical for-mula shown in Equation 4.2, which is normallyused for rural feeders.

Loss factor compares

average losses with

peak losses.

FIGURE 4.2: Relationship Between Load Factor and Loss FactorPer Unit.

0

1.0

0.8

0.6

A

C

B

0.4

0.2

0.2 0.4 0.6

Per Unit Load Factor

0.8 1.0

Curve A: Loss Factor = Load Factor

Curve B: Loss Factor = (Load Factor)2

Curve C: Loss Factor = 0.2 Load Factor + 0.8 (Load Factor)2

PerUnitLossFactor

126 – Sect ion 4

This equation is shown as curve C in Figure 4.2.A more thorough discussion of load factor

and loss factor may be found in the NRECADistribution System Loss Management Manual,pages 17–20.

Because the load factor of a cable determinesits ampacity value, consideration must be givento future load factors during the expected life ofthe cable. Choosing a load factor of 100 percentgives the minimum ampacity value, with all otherconditions being equal. An improperly high loadfactor could lead to the choice of cable one ortwo sizes larger than necessary. Knowing the ef-fect of the other conditions on cable ampacity willallow the engineer to make a more informed de-cision about the value of load factor chosen.

Soil Thermal ResistivitySoil thermal resistivity (rho) is an important ele-ment that affects cable ampacity. The tendencyof soil surrounding a buried cable to hinder theflow of heat from the cable or conduit surface isa fundamental property called soil thermal resis-tivity, expressed in degrees Celsius-centimeterper watt (°C-cm/watt). Rho is important in theselection of load capabilities of UD cables. Insome instances, more than one-half the totalconductor temperature rise is caused by im-paired heat flow through theearth. Rho can be measuredalong a specific route to helpin selecting the proper cablesize. However, measurementsare usually difficult and time-consuming to perform. Mostutilities assume soil propertiesthat have led to reliable performance in the past.Selecting an ampacity value is complicated fur-ther because rho depends on many conditionsthat are not constant through the soil profile andcan change with the seasons of the year.

The thermal resistivity of a soil depends on the

4type of soil (its texture and mineral content), themoisture content, and the structural arrangementof the soil particles. Generally, the higher themoisture content, the lower its thermal resistanceand the better its heat-dissipating ability. Certainclay soils tend to dry out and become bakedwhen heated beyond a certain temperature; thisdrives away the moisture and may permanentlyincrease their thermal resistivity. Clay is also anexample of a soil that shrinks when dry, therebylosing contact with the cable, which creates anair layer between the soil and the cable surfaceand adds an extreme thermal resistance to theheat dissipation path. As the thermal resistancearound the cable increases, the cable temperaturerises. If the cable temperature stabilizes at a safelevel, the soil is considered stable. If the tempera-ture continues to rise above an acceptable level,the soil is considered thermally unstable.

Figure 4.3 shows the variation of thermal re-sistivity with moisture content for various typesof soils. As the moisture content is reduced, re-sistivity rises slowly until a critical moisture levelis reached; the thermal resistivity then starts toincrease at a much higher rate. Electric PowerResearch Institute-sponsored research has shownthat, at high moisture levels, water fills the gapsbetween soil particles, which increases the effec-tive cross-sectional area available for heat trans-fer, thus reducing the thermal resistivity of thesoil (Boggs, Chu, and Rhadhakushna, 1980).

As the moisture migrates away from the cablesurface for any reason, heat conduction takesplace through a solid soil matrix. Within the ma-trix, the particles have only point-to-point con-

tact with each other. Theability of different soils todissipate heat under theseconditions is determined bythe particle size distribution(packing efficiency) of the soiland, to a lesser extent, by theshape of the particles. Figure

4.3 shows that, for well-graded soils such aslimestone screenings (a quarry waste by-prod-uct), thermal resistivity is basically constantdown to low moisture contents of approximatelytwo percent. Below this moisture level, the ther-mal resistivity is shown to quickly increase.

High soil thermal

resistivity reduces

cable ampacity.

Equation 4.2

Loss Factor=0.2 Load Factor+0.8(Load Factor)2


The ampacity tables in Appendix G list cable-soil interface temperatures alongside the currentvalues. These interface temperatures show thatsoil drying around a hot cable can lead to anincrease in soil thermal resistivity and increasedsoil and conductor temperatures. Interface tem-perature is the temperature attained by the out-side surface of directly buried cable, directlyburied duct, or concrete encasement. Utilityengineers commonly rate cables on the basis ofthis method. Field studies suggest an interfacetemperature of 50°C to 60°C be used for clayand loam soils and 35°C for sandy soils (Armanet al., 1964). Interface temperatures have beenused in the past to rate cables because no othersimple, dependable method exists.

Thermal efficiency of the soil depends mainlyon its moisture content. In most areas of the UnitedStates, soil moisture varies with the seasons. Usual-ly during the cooler months, January through May,rain keeps the soil well saturated. The warmermonths have less rainfall and the soil dries out.Because thermal resistivity and water content ofthe soil are interrelated, it is reasonable to assumethat these two properties will vary with seasonaland climate factors as well. Figure 4.4 showsmeasured variation of soil thermal resistivity atfour locations on a monthly basis. The resistivityis shown to generally increase during the hot/dry months of August, September, and October.

4

FIGURE 4.3: Thermal Resistivity Versus Moisture Content for VariousSoil Types. Source: Boggs, Chu, and Rhadhakushna, 1980.

030

60

90

120

150

180

210

1 2 3

Crushed Shale

Silty Sand

Ottawa Sand

Critical Moisture Content =

Fire Valley SandStone Screenings

4 5Percentage Moisture Content

ThermalResistivity(°C-cm/Watt)

6 7 8 9 10

Jan40

50

60

70

80

90

100

110

120

130

140

150

160

Feb Mar Apr May Jun1952

Jul Aug Sep Oct Nov Dec

ThermalResistivity(°C-cm/Watt)

FIGURE 4.4: Thermal Resistivity of Soil at Various Locations.Source: EEI Underground Systems Reference Book, 1957.

In most cases, for a soil of a particular typeand a fixed water table level, the moisture con-tent increases with depth. The greater the depth,the less the change in moisture during the year.A higher water content generally leads to alower thermal resistivity.

Years ago, experiments were made that inves-tigated the differences in temperature rise forequally loaded cable buried at intermediatedepths from three to 20 feet. As expected, theresults showed a lower rho and less temperature

Soil thermal resistivity

changes with

moisture content.

128 – Sect ion 4

rise at 20 feet compared with three feet. How-ever, the increase in cable ampacity could neveroffset the extra cost of deeper burial. Standardindustry practice is approximately three feet asan acceptable minimum depth for almost all in-stallations outside urban areas. Unfavorable na-tive soil conditions near the surface can beovercome for short runs by using a good ther-mal backfill in the vicinity of the cable.

Ambient Soil TemperatureAmbient soil temperature affects UD cable ampac-ity and must be considered when using ampacitytables. Every ampacity table has been computedfor a specific ambient temperature. The temper-ature rise of the cable is added directly to the

4

Temperature, °C

Location Summer Winter

Northern United States 20 to 25 2 to 15

Southern United States 30 to 35 10 to 20

TABLE 4.2: Typical Ambient Soil Temperatures at a Depth of 3.5 Feet.Source: ICEA Publication No. P-46-426.

FIGURE 4.5: Effect of Depth on Soil Temperatures as Influenced by Seasonal TemperatureVariations. Source: EEI Underground Systems Reference Book, 1957.

JanDec–5

0

5

10

15

20

Feb Mar Apr

Air

May Jun

1.5

3

6.5

16

Depth BelowSurface (Feet)

Months

Temperature(°C)

Jul Aug Sep Oct Nov Dec

ambient temperature. The ambient temperatureis the normal soil temperature at the burialdepth of the cable that would exist if the cablewere not there.

The change of ambient temperature below theearth’s surface is caused by seasonal exchangeof solar energy between air and earth. The earthacts like a heat sink in the summer and returnsheat to the air in the winter. Measurements showthat soil temperature decreases with depth insummer and increases with depth in winter. Fig-ure 4.5 shows that the temperature change fol-lows essentially a sinusoidal curve that changeswith the seasons. The cycle does not vary muchfrom year to year.

Cyclical temperature changes below groundvary considerably from place to place and mustbe known for the specific location being consid-ered. If it is not feasible to make temperaturemeasurements at the site, usable temperatureranges may be obtained from the state Depart-ment of Agriculture or the agricultural school ofa state university. Table 4.2 gives typical temper-ature ranges that may be used when site-specificdata are not available.


Daily variations in air temperature producenegligible changes in ambient earth tempera-tures below one foot. Investigations have shownthat, at depths below 36 inches, ambient soiltemperatures lag the air temperature by abouttwo weeks to one month because of the highspecific heat of the soil.

Cable Configuration and Circulating CurrentVarious aspects of installation can affect theamount of current a cable can carry. For single-phase primary UD cable, dielectric loss is usuallyconsidered negligible when ampacity is calculat-ed. Therefore, the current rating of most single-phase UD applications is limited by current-relat-ed losses in the conductor and neutral, plus theheat-sink quality of the surrounding soil.

In a balanced three-phase application usingconcentric neutral cable, there is no return cur-rent because the phase currents vectorially addto zero at the load. No return current means themagnetic field outside the concentric neutral ofeach phase is not totally canceled out. Load cur-rent flowing in the other two phases will cancelsome of the magnetic field produced by currentin one phase. Because the net magnetic fieldaround the phase is not completely canceled, itproduces a voltage difference along the lengthof the concentric neutral. In the same way, volt-age differences are produced along the concen-tric neutrals of the other two phases.

Safety standards require that the concentricneutrals of all jacketed UD cables be groundedand connected together at both ends of thecable run, and at as many intermediate points asrequired by the NESC. This necessary groundingof the neutrals at more than one point creates across connection which short-circuits the voltagebetween them and allows circulating currents toflow. The circulating currents produce heat. Thisheat, when added to the mutual heating effectof the other conductors in a trench, decreasesthe ampacity of the cable circuit.

Voltage differences—and, thus, neutrallosses—are proportional to the mutual reactanceof the cable system. The most common way toreduce mutual reactance is to place the cablescloser together. However, the axial spacing can-not be reduced below one cable diameter, so

mutual reactance will always exist. Another pointthat must be considered when spacing cablesclose together is the mutual heating effect causedby the three conductors. Mutual heating will de-crease the load-carrying ability of the system.

Another way to reduce circulating currentlosses is to increase the resistance of the concen-tric neutral. This may be done by reducing thenumber or size of the wires. Industry practice isto list concentric neutral sizes in relation to theresistance of the central conductor. For example,a cable with 1/3-neutral would have a concen-tric neutral resistance three times the phase con-ductor. Engineers recognize that the concentricneutral physically protects the cable. For thisreason, cable is usually purchased for standardapplications with a concentric neutral made upof at least six No. 14 AWG copper wires.

The preceding discussion shows that a three-phase installation is more involved in terms ofampacity and that more factors limit its ampacitythan for a single-phase circuit. In addition to theconductor losses and the thermal quality of thesoil, the arrangement of the phases in relation toeach other affects the total system losses and,thus, the circuit ampacity.

INSTALLATION CONFIGURATIONSPhysical Arrangement of PhasesExample 4.1 shows how the physical arrangementof the phase conductors can affect ampacity.

Observations from Ampacity TablesThe following general observations can be madefrom reviewing the 1962 ICEA ampacity tablesand IEEE Standard 835-1994 for different instal-lation configurations:

• Circulating current losses decrease andampacities increase with increasing concentricneutral resistance.

• The smaller the phase conductor, the smallerthe variation of the circuit ampacity with neu-tral resistance.

• For large conductors, there is a large variationof ampacity with neutral resistance.

• The variation of ampacity with concentricneutral resistance is generally greater forspaced than for trefoil configurations.

4

130 – Sect ion 4

4

Use flat spacing for small

conductor installations.

EXAMPLE 4.1: Comparing the Ampacity of Trefoil and Flat-Spaced Configurations.

Consider two direct-buried, three-phase primary circuitsusing concentric neutral jacketed cable. Circuit 1 shownin Figure 4.6 is in a closely spaced trefoil or cloverleafconfiguration. Circuit 2 is a flat configuration with “main-tained spacing” of approximately 7.5 inches betweenphases, as seen in Figure 4.7. For easier comparison ofthe two installations, excerpts from their ampacitytables are listed in Table 4.3.

Examination of the two configurations of Table 4.3shows that, for conductor sizes of 350 kcmil and larger,the trefoil arrangement produces fewer losses andgreater ampacity as the load and load factor of thecircuit increase. For 4/0 AWG and smaller conductors,the spaced configuration gives greater current-carryingcapability.

36”

36”

A B C

7.5” 7.5”

FIGURE 4.6: Trefoil or TriangularCable Configuration.

FIGURE 4.7: Flat ConductorConfiguration, Maintained Spacing.

A table similar to 4.3 can be made for aluminumconductors.

Table 4.4 shows that, for aluminum conductor sizes upto 500 kcmil, the flat-spaced configuration gives greaterampacity values than does the trefoil. For the largerconductor sizes, the trefoil configuration gives higherampacity ratings because circulating current losses aregreater when flat spacing is used.

Continued

Trefoil Configuration (Amperes) Flat-Spaced Configuration (Amperes)

Conductor Size 75% Load Factor 100% Load Factor 75% Load Factor 100% Load Factor

4/0 (1/3 neut) 404 360 432 377

350 (1/3 neut) 519 460 516 448

500 (1/3 neut) 609 535 572 496

750 (1/3 neut) 696 608 635 548

1,000 (1/6 neut) 814 706 705 605

* IEEE Standard 835-1994Note. Soil rho = 90, Conductor Temperature = 90°C, Ambient Soil Temperature = 25°C

TABLE 4.3: Ampacity Table for 15-kV Copper Conductor, Direct Buried, Single Circuit,75% and 100% Load Factor.*


Conclusions from Ampacity TablesAfter a comparison of the IEEE Standard 835-1994 for trefoil against spaced arrangementswith short-circuited and multigrounded con-centric neutrals, the following conclusions canbe drawn:

• When neutral losses are low in both cases,the ampacity of the spaced configuration willbe more than the trefoil arrangement becauseof the effect of lower mutual heating.

• When the circulating current losses of thetrefoil are measurably greater than the spacedconfigurations, their ampacities will be essen-tially the same.

• For larger size cables, it is generally betterto keep them as close together as possiblebecause the higher circulating currents ofthe spaced cables provide greater lossesand lower ampacities than does the mutualheating effect of the trefoil configuration.

Note that if single cables are installed in aspaced configuration in individual steel conduit,the same fields that produce losses in the con-centric neutrals will also cause eddy currentsand unacceptable heating of the steel. The

losses of the conduit added to the other lossesof the circuit will reduce the ampacity evenmore. In some cases, steel conduit may reachtemperatures adequate to cause cable failure bymelting. For this reason, nonmagnetic conduitmust be used for high-ampacity circuits wherephases are enclosed in individual conduits.

The preceding discussion will prove useful incomparing closely spaced with spaced three-phase circuits. When an installation specificationcalls for either a trefoil or maintained spacing(flat horizontal configuration), close attentionshould be paid to the spacing when the cable islaid. Otherwise, inattention to detail could leadto a marginal installation after much effort hasgone into selecting the right cable and configu-ration for the project.

CONDUIT APPLICATIONSInstallation in Conduit or DuctIn this manual, the terms conduit and duct areused interchangeably to mean nonmetallic, non-magnetic tubes made primarily of polyvinylchloride or polyethylene. A duct bank meansone or more runs of conduit which are usuallyencased in concrete that extends the full lengthof the run.

4EXAMPLE 4.1: Comparing the Ampacity of Trefoil and Flat-Spaced Configurations. (cont.)

Trefoil Configuration (Amperes) Flat-Spaced Configuration (Amperes)

Conductor Size 75% Load Factor 100% Load Factor 75% Load Factor 100% Load Factor

1/0 (full neut) 216 194 241 214

1/0 (1/3 neut) 216 195 247 218

4/0 (1/3 neut) 318 284 361 311

350 (1/3 neut) 417 370 446 387

500 (1/3 neut) 502 442 513 443

750 (1/3 neut) 604 529 575 498

1,000 (1/6 neut) 716 623 675 582

* IEEE Standard 835-1994Note. Soil rho = 90, Conductor Temperature = 90°C, Ambient Soil Temperature = 25°C

TABLE 4.4: Ampacity Table for 15-kV Aluminum Conductor, Direct Buried, Single Circuit,75% and 100% Load Factor.*

132 – Sect ion 4

Laying cable in conduit is being done bymany electric utilities. Articles in the technicalpress have shown that a few systems are justify-ing using conduit for all UD installations becausecable replacement is much easier. In northernclimates, it is strongly recommended that con-duit be used because digging trenches in frozenground can be costly and very time-consuming.Conduit can also provide some protection againstdig-ins. A sealed conduit system is also useful tokeep water away from cables to reduce insula-tion treeing. However, effective sealing is verydifficult to achieve in practice. Underground ductis also used to protect the cable from rodentdamage. Cables are usually installed in ductswhere they pass under roadways, sidewalks, orother paved areas (see Figure 4.8). Becausecable in conduit has less load-carrying abilitythan direct-buried cable does, conduit applica-tions will be reviewed in more detail.

Pros and Cons of Cablein ConduitThe total thermal circuit of acable in conduit can be visual-ized as four thermal resis-tances in series:

1. Thermal resistance from the conductorsurface to the outer jacket surface,

2. Thermal resistance from the jacket surfaceto the inner surface of the conduit wall,

3. Thermal resistance of the conduit material,and

4. Thermal resistance of the soil.

Heat flow through these thermal resistancescauses the temperature of the insulation to riseabove ambient temperature. The air between thecable and the inner conduit surface is the mainreason why heat is not absorbed by the soil asefficiently as with direct burial, and why a cablein conduit has less ampacity. The concept can bemore easily understood by comparing typical ther-mal resistivity of the various materials. For exam-ple, the thermal resistivity of air is 4,000°C-cm/watt,PVC conduit is approximately 480, and soil isapproximately 90. It should be remembered thissame principle might apply to cables installedwith a vibratory plow. In stiff soils the earth maynot heal itself tightly back against the cables,leaving air pockets. Consideration might be giv-en to de-rating certain plowed-in cables to ca-ble-in-conduit ratings.

The air space acts essentially like an insulat-ing blanket to impede the flow of heat to the

surrounding soil. Once an airinterface exists, heat transferis not solely by conductiondirectly from the cable sur-face to soil; rather, it ismostly by radiation and con-vection into the air space.The inside diameter of the

conduit should be as small as possible for bet-ter heat flow. However, the inside diameter ofa conduit has little effect on the final tempera-ture reached by the insulation for the typicalconduit sizes used by utilities. For this reason,ampacity tables do not list different ampacitiesfor different conduit sizes.

4

FIGURE 4.8: Direct-Buried Duct Bank Installation Using Rigid Nonmetallic Conduit.

Paved Driveway Paved Driveway

36”

18”

36”

Conduit Installations

=

Lower Cable Ampacity


The minimum conduit size required to holdone or more primary cables depends on severalelements dictated by the installation. The insidediameter should be large enough to accommo-date any movement by the cable(s) caused bythermal expansion. Certain installations may dic-tate choosing a large conduit diameter to allowa higher ampacity cable to be installed later.When a single cable or a bundle of three JCNcables is being pulled, the conduit must be largeenough to allow unimpeded passage.

Table 4.5 summarizes the pros and cons ofcable circuits in conduit. If more circuits areadded to an existing duct bank or trench, theampacity of all circuits must be reduced.

Conduit in Air for Riser Pole ApplicationsAnother cable installation element that needs tobe considered in underground applications isthe transition from underground to overhead ata riser pole (Hartlein and Black, 1983). Utilitiesusually place cable in vertical conduit for pro-tection. It must be determined if this short sec-tion in a protective riser willbe the limiting factor in acable installation.

There are no simple estab-lished methods to rate theriser portion of a cable circuit.Usually, engineers assume thatunderground direct-buriedcable runs cooler than doesthe cable section in the riser. Appropriate de-rat-ing factors based on field and laboratory experi-ence are then applied to reduce the circuitampacity when a riser is present. This method isbased on the principle that the current rating ofa total cable system is limited by the cable seg-ment that operates at maximum temperature.

4Pros Cons

Cable easily replaced (if not fused or frozen) Higher installed cost

Greater physical protection (for identical cables) Lower ampacity

Longer life (for identical cables)

Provision for load growth (replace with larger cable)

TABLE 4.5: Pros and Cons of Installing Cable Circuits in Conduit.Cable conductor temperatures in a riser appli-

cation depend on the following four factors:

1. Number of cables in the vertical conduit,2. Venting method,3. Solar radiation, and4. Riser inside diameter.

When three cables are placed in a single riser,mutual heating will affect cable conductor tem-perature. At a conductor temperature of 90°C,three cables can have 30 percent less ampacitythan can a single cable in the same riser. Addi-tional tests have shown that the heat generatedby three cables in a riser will always run hotterthan the direct-buried portion of the same cir-cuit. The higher temperature in the riser meansthe rating of the composite circuit is limited bythe riser segment in three-phase, direct-buriedapplications.

A vertical riser can be installed in one of threeways that will affect circuit ampacity. The instal-lation configurations are listed from higher tolower ampacity values:

1. Open at the top and vented at the bottom,2. Open at the top and closed at the bottom, or3. Closed at both top and bottom.

Proper venting will greatly increase ampacitywhen compared with a completely closed riserthat prevents natural air circulation around thecable. Closing the top reduces the convective

heat transfer capability fromthe cable surface and insidesurface of the riser. The pre-ferred installation configurationis to allow the free flow of airthrough the riser, which is ob-tained with an open top and avent at the base. Laboratorytests have shown that at a load

factor of 100 percent, a properly vented riser canincrease ampacity between 10 and 25 percentwhen compared with a completely closed riser.The vent configuration needs to comply with theNESC and good engineering judgment.

Direct exposure of the riser to the sun will de-crease the ampacity of a cable in a vertical riser.

Venting risers at

top and bottom

increases ampacity.

134 – Sect ion 4

Incident solar radiation perunit area is equal to 900watts/m2. This is a typicalvalue for a sunny, midsummerday throughout the UnitedStates. The influence of solarheating in a riser applicationoperating at a load factor of100 percent can reduce the current rating ofcable by 15 percent for a completely closed riserand five percent for properly vented risers be-tween day and night. Because ampacity tableslist conduit-in-air ampacity values at an ambientair temperature of 40°C (104°F), solar de-ratingfactors need be applied only during the hottestdays of the summer. Note that Table 4.1 givesampacity correction factors for ambient air tem-peratures other than 40°C and different conduc-tor temperatures. This table can be used for riserpole applications.

Radiation heat transfer plays a large role intotal heat dissipation from cable and riser sur-faces. For maximum efficiency, riser materialshould be a light color (gray) to reflect some ofthe sun’s rays and to allow heat to be given offby the riser surface at a higher rate.

Cable in a large-diameter, vented riser willconsistently operate at a lower temperature thanwill the same cable carrying the same current ina smaller conduit because the larger opening al-lows more airflow through the riser. In addition,the larger surface area increases heat dissipationby convection and radiation. Conductor temper-ature differences between large- and small-diam-eter risers can range from 2°C to 15°C.

Substation ExitsSubstation exits are generally the highest ampac-ity application of underground primary cable onutility systems. Because cable in conduit has lessload-carrying ability than does direct-buriedcable, both configurations applied in vertical ris-ers will be reviewed in more detail.

Consider the condition in which two cable cir-cuits in trefoil arrangement end on a double-cir-cuit riser pole. When referring to IEEE 835-1994ampacity tables to select cable current ratings forriser pole applications, use the tables for trefoilcable in isolated conduit in air. When conduits

that contain up to three cur-rent-carrying conductors (withneutral) are kept more thanone conduit diameter apart(from surface to surface), nocorrection of ampacity ratingsneed be made because of mu-tual heating. This is because

air circulation, even at an elevated ambient tem-perature of 40°C, will prevent convection heatingfrom reducing the cable ampacity, so that it’s com-parable to that of an isolated conduit in free air.

The effect of the vertical conduit run on un-derground cable ampacity ratings is best shownby comparing its ampacity with four types ofunderground configurations. The comparison isshown in Table 4.6 for copper conductors andTable 4.7 for aluminum conductors.

Tables 4.6 and 4.7 list the ampacity of singleand double three-phase circuits in trefoilarrangement made up of two-conductor, single-phase UD cables. Conductor sizes range from4/0 AWG to 1,000 kcmil. The cables are directburied, buried in conduit, and vertical conduit inair for the riser pole application. Conditions thatrelate to the underground and riser pole installa-tions are shown below the ampacity values. Thefour circuit configurations are shown in Figure4.10 as configurations 1 and 4, and 3 and 5.

The two tables show that, for the buried con-duit installation configurations, the riser doesnot limit the ampacity of the double circuit, butwill limit single-circuit applications (shadedcells). For the direct-buried conditions, the verti-cal run limits the installation for the cable sizesand configurations shown in the shaded portionof the tables. Note that for the single-circuit, di-rect-buried case, the riser limits ampacity for allcable sizes and for both types of conductor.

ICEA and IEEE ampacity tables for conduit-in-air applications are different from their under-ground counterparts. For air installations, thetables assume there is no wind and no sun load-ing and that the conduit is not ventilated. Asnoted in a previous subsection, Conduit in Airfor Riser Pole Applications, solar radiation wasfound to decrease riser ampacity, whereas vent-ing increases riser ampacity over the rating of ariser closed at both ends. Therefore, to prevent

4Sun loading will

decrease riser

ampacity.


the de-rating of riser pole (conduit-in-air) ampacityvalues resulting from solar effects, the riser mustbe open at the top and vented at the bottom.

Conduit-in-air ampacity tables do not list dif-

ferent current values for different average airtemperatures. Instead, ampacities are listed for40°C, which is considered conservative for mostinstallations. The tables also do not show am-

4Direct Buried** Riser Pole Buried in Conduit**

VerticalCable Size 1 Circuit 2 Circuits Conduit in Air 1 Circuit 2 Circuits

4/0 360 301 267 289 256

350 460 381 338 370 326

500 535 440 409 439 383

750 608 496 455 502 434

1,000 706 573 554 599 512

Underground Riser Pole

90°C conductor temperature 90°C conductor temperature

100% load factor 40°C average air temperature

25°C ambient earth temperature No solar radiation, venting, or wind

* Ampacity values are from IEEE Standard 835-1994.** Circuit configurations are shown in Figure 4.10 as configurations 1 and 4, and 3 and 5, respectively.

TABLE 4.6: Ampacity Values—15-kV Cable, Trefoil Configuration, Copper Conductor.*

Direct Buried** Riser Pole Buried in Conduit**Vertical

Cable Size 1 Circuit 2 Circuits Conduit in Air 1 Circuit 2 Circuits

1/0 195 165 145 156 140

4/0 284 238 212 228 202

350 370 307 276 298 262

500 442 365 347 364 318

750 529 432 411 437 379

1000 623 506 508 528 452

Underground Riser Pole

90°C conductor temperature 90°C conductor temperature

100% load factor 40°C average air temperature

25°C ambient earth temperature No solar radiation, venting, or wind

* Ampacity values are from IEEE Standard 835-1994.** The above circuit configurations are shown in Figure 4.10 as configurations 1 and 4, and 3 and 5, respectively.

TABLE 4.7: Ampacity Values—15-kV Cable, Trefoil Configuration, Aluminum Conductor.*

136 – Sect ion 4

pacity variations caused by different load factorsfor cables suspended in conduit exposed to air.There is no load factor variation because there isno heat-sink cooling effect for the conductor/airsystem as exists for buried cable. In a riser, asthe load increases to a peak, the conductor tem-perature increases much more quickly than if itwere buried in soil. Thus, for riser applications,the load factor is considered to be 100 percent,because the thermal time constant for thecable/air system is very short.

Instead of circular conduit, some utilities useU-guard for riser pole applications. U-guard, asthe name implies, is a U-shaped section withflanged edges that is attached to a pole with lagbolts. It is used to cover andprovide suitable protection forthe cable. U-guard usuallydoes not need to be vented atthe base because an air spaceis assumed to exist betweenthe pole and flanges to allowenough air entry to produce achimney-cooling effect. How-ever, many cooperatives installa vent at the base of U-guard to ensure optimumairflow and increased cable ampacity for allthree-phase and most single-phase installations.

4

FIGURE 4.9: Single-Phase U-GuardInstallation with Vented Base.

This added feature is particularly important if aU-guard backing plate is used, because thisarrangement has few, if any, significant air gaps(see Figure 4.9). For a double-circuit riser pole,U-guard should be placed on opposite sides ofthe pole to prevent mutual heating and minimizethe chance of simultaneous damage from vehic-ular impact.

Regardless of whether the riser is conduit orU-guard, venting should only be installed whereit is required to obtain sufficient cable circuit am-pacity. This is because the venting fixtures are moreexpensive than normal conduit and require addi-tional installation effort. Venting fixtures also slight-ly reduce the security of the riser installation and

are more subject to damage byoutside impact.

Whether conduit or U-guard is used as a riser, itis recommended that a 90°elbow with a separate endbell be installed three feetbelow grade level. This instal-lation will ensure that thecable is at the proper depth

near the riser pole. The elbow/bell end combi-nation helps prevent cable damage duringpulling. After the cable is installed, it also helpsprotect against dig-ins around the base of thepole and minimizes conduit pressures on cableif soil shifts.

Emergency Overload RatingsFor years, cables have been rated for operationat a maximum temperature of 90°C. When thesetype cables are loaded above a conductor oper-ating temperature of 90°C for XLPE, TR-XLPE,and EPR insulations, the cable is consideredoverloaded. Many utilities and cable manufactur-ers are now specifying and rating cables for 105°Cas a standard overload temperature. Cooperativesshould weigh carefully the use of this rating, andconsider as well the maximum operating temper-ature rating of cable terminations and joints.

Overloading the cable will heat its insulationabove its maximum operating temperature limits.The insulation temperature limits have been setby standards to maintain the integrity of the insu-lation for an increased life expectancy. Emergency

Riser vents should

be installed only

where necessary for

increased ampacity.


operating temperature limits apply only to theinfrequent higher loading of a line caused byan unplanned outage of a nearby cable or loadsharing for a nearby substation. Standards statethat the emergency overload conductor temper-ature of 130°C (or 140°C for the 105°C rating)should not be exceeded for more than 100 hoursin any 12 consecutive months nor for more than500 hours during the lifetime of the cable.

Cable aging accelerates with high temperaturesand accumulates over time in a way similar toaging in transformers. For these reasons, emer-gency overload ratings always specify both atemperature and a time limit for events over thelifetime of the cable (Aluminum Association Inc.,1989). The ratings have been derived from in-dustry operating experience and could changeas newer and better insulation materials becomeavailable. Emergency overload ratings are set byICEA, NEMA, and ANSI/IEEE standards. Table4.8 lists the emergency overload temperaturesfor the two types of insulation specified by theRUS, plus temperatures for outdated HMWPEwhen used as an insulation material.

AMPACITY TABLESTable 4.1 lists the ampacities for single-phaseUD cable direct buried and in conduit forcopper and aluminum conductors.

The three-phase ampacity tables and associ-ated ampacity ratings for underground distribu-tion cables provided in Appendix G are basedon the following conditions:

• 60-Hz.• 15 kV, 25 kV, and 35 kV.• Load factors of 75 percent and 100 percent.• Three, two-conductor, concentric neutral,

single-phase, primary UD cables. Installationconfigurations are shown in Figure 4.10.

• Conductors Class B Stranding Copper and Aluminum 1/3 Concentric Neutral (1/6 for 1,000 kcmil)

• Conductor Sizes 1/0 AWG Solid Conductor—Aluminum

Only—Full Neutral 4/0 AWG Class B Stranding—Copper

and Aluminum 350 kcmil Class B Stranding—Copper



and Aluminum 1,000 kcmil Class B Stranding—Copper

and Aluminum• Cable Specification

To Meet RUS Cable Specification 1728F-U1: Insulation: EPR or TR-XLPE Insulating Outer Jacket Insulation Thickness: 220 mil @ 15 kV

260 mil @ 25 kV345 mil @ 35 kV

• All concentric neutrals are shorted andgrounded at several points in the circuit, asper the National Electrical Safety Code.

4Normal Operating Emergency-Load Short-Circuit Temperature of Cable Conductor

Insulation Temperature (°C) Temperature (°C) (less than 30 seconds) (°C)

Thermosetting 105 140* 250TR-XLPE and EPR

Thermosetting 90 130* 250TR-XLPE and EPR

HMWPE 75 95 150

* Operation at the emergency overload temperature of 130°C (266°F) and 140°C (284°F) shall not exceed100 hours in any 12 consecutive months nor more than 500 hours during the lifetime of the cable.

Note. Lower temperatures for emergency overload conditions may be required because of other types of materialused in the cable and in the joints and terminations or because of cable environmental conditions.

TABLE 4.8: Abstract of ICEA Standards for Maximum Emergency-Load and Short-Circuit-LoadTemperatures for Various Insulations.

138 – Sect ion 4

• Ratings include dielectric loss and inducedac losses.

• Conduit Conduit used in Configurations No. 3, 5, 6,

and 7 is Schedule 40, PVC conduit. Maxi-mum fill requirements are 40 percent forthree cables in a conduit per pending RUSSpecification 1728F-U1.

• Temperature Limitations Ambient Soil = 25°C Conductor = 90°C Neutral (assumed) = 80°C Conduit (assumed) = 70°C

• Thermal resistivity (rho) of various materialswas assumed as follows: Soil = 90°C-cm/Watt Insulation and Extruded Shields

= 400°C-cm/Watt Conduit and Duct = 480°C-cm/Watt Concrete = 85°C-cm/Watt

• The ampacities for 15-kV class cable werecalculated with 15 kV as the operating volt-age. If 12.47 kV is used, the ampacities willbe marginally higher (<1%).

Adjustments for Changes in ParametersIf the engineer needs to make certain changesin parameters to match them with actual siteconditions or to do a sensitivity analysis onvarious parameters, the following formulasmay be used.

Adjustment for Changes in AmbientSoil TemperatureThe ampacities in Appendix G are based on anambient temperature of 25°C. To correct ampaci-ties based on maximum conductor temperaturesfor different ambient temperatures, use the for-mula shown in Equation 4.3.

The factors shown in Table 4.9 may be used

4

FIGURE 4.10: Three-Phase Cable Installation Configurations.

Configuration 136”

36” 30”

19”

7.5”

7.5”

18”

19”

19” 19” Duct Bank

7.5”

5”

30”

19”

7.5” 7.5”

7.5”

26.5”

19” 26.5” Duct Bank

5”

18”

36”

36”

36”

Configuration 5 Configuration 6 Configuration 7


A B C


to correct ampacities based on maximumconductor temperatures for earth ambienttemperatures of 20°C or 30°C.

Adjustment for Changes in AmbientAir TemperatureTo find ampacities for ambient air temperaturesother than those found in the individual tables,multiply table values by the correction factorsshown in Table 4.10.

4

Equation 4.3

where: Tc = Maximum conductor temperature from ampacity tableI = Ampacity shown for Tc at ambient earth temperature of 25°CTa' = New ambient earth temperatureI' = Adjusted ampacity for ambient earth temperature Ta'

I' = × ITc – Ta'Tc – 25

Ambient Temperature Correction Factor(°C) (Maximum Conductor Temperature)

75°C 90°C

20 1.049 1.037

30 0.949 0.960

TABLE 4.9: Correction Factors to Convert from 25°C Ambient SoilTemperature to 20°C and 30°C.

ConductorTemperature

(°C) Ambient Air Temperature

30°C 35°C 40°C 45°C 50°C

75 0.97 0.92 0.86 0.79 0.72

85 1.06 1.01 0.96 0.90 0.84

90 1.10 1.05 1.00 0.95 0.89

100 1.17 1.12 1.08 1.03 0.98

110 1.23 1.19 1.15 1.11 1.06

125 1.31 1.27 1.24 1.20 1.16

130 1.33 1.30 1.27 1.23 1.19

150 1.42 1.39 1.36 1.33 1.30

TABLE 4.10: Correction Factors for Various Ambient Air Temperatures.Source: Okonite Company, Engineering Data for Copper and AluminumConductor Electrical Cables, Bulletin EHB-90, 1990.

Adjustment for Change in ConductorTemperatureThe ampacities (I') for conductor temperaturesother than those included in the tables (e.g.,emergency conductor temperatures) can be ap-proximated using the formula in Equation 4.4.

When Tc' is greater than Tc, Equation 4.4 willgive conservative values because it is based onthe ratio of direct-current losses at the two tem-peratures, whereas the ratio of the ac conductorand concentric neutral losses to dc conductorlosses decreases with increasing conductor tem-perature. For example, the ampacity at 110°Cconductor temperature may be as much as fivepercent higher and at 130°C as much as 10 per-cent higher than values calculated fromEquation 4.4. Deviations from true ampacitieswill depend on the conductor size, concentricneutral size, and installation configuration. Equa-tion 4.4 is more precise for smaller conductorsand higher resistance concentric neutrals (ICEAP-53-426, p. VII, May 1976).

Figure 4.10 shows the seven cable installationconfigurations whose ampacities have beenlisted in the ampacity tables.

Note: The ampacities listed in Appendix G arebased on a conductor temperature of 90°C andan ambient soil temperature of 25°C. On thebasis of these assumptions, many of the calcu-lated current values may exceed the maximumpermissible earth interface temperatures for vari-ous types of soils. Experience has shown that in-terface temperatures of 50°C and 60°C should be

Equation 4.4

where: I' = Ampacity for conductor temperatureTc, in amperes

Tc' = New or emergency conductortemperature, in °C

Ta = Ambient earth temperature, in °Cτc = Magnitude of the difference between

0°C and the zero electrical resistanceof copper (234.5°C) or aluminum(228.1°C)

Tc = Maximum conductor temperaturefrom ampacity table, in °C

I' = × ITc' – TaTc – Ta

τc + Tcτc + Tc'

×

140 – Sect ion 4

4

EXAMPLE 4.2: Single-Phase UD Cable Ampacities.

A cooperative is planning to stock UD cable to meet the growing de-mand for new 12.47-kV underground installations. This cable will beused with 200-ampere class accessories. The cable will also be usedto replace any faulted feeder sections on an as-needed basis. The con-ductor cable with the most installed circuit miles on the system is 1/0aluminum. With this in mind, the engineer decided to check the am-pacity of 1/0 cable for typical installations that exist on the system tofind which cable sections could limit the current rating of an entirecable run.

The cooperative direct buries its single-phase cable in all instancesexcept for road crossings and riser pole installations. Go to the begin-ning of this section to find the ampacity rating for underground installa-tions. Assume an operating conductor temperature of 90°C, soil rho =90°C-cm/watt, and ambient soil temperature of 20°C.

Using Table 4.1, find the ampacity of direct-buried TR-XLPE 1/0aluminum cable:

Because the ampacity ratings given in Table 4.1 are for an ambient soiltemperature of 25°C, higher values can be expected if the soil tem-perature is actually 20°C. As Equation 4.3 indicates, the cable ampac-ity at 20°C can be found by multiplying the existing values by thecorrection factor:

Cable ampacity for a soil temperature of 20°C is as follows:

For the riser pole cable section, the ampacity value is found in Table 4.1under the “Duct in Air” column:

This ampacity value is based on a riser that is closed at the top and bot-tom with no sun loading and no wind. Previous discussions have shownthat venting conduit at top and bottom and leaving the top of U-guardopen can increase riser ampacity, whereas solar radiation can reduceits rating. So if sun loading is considered, the riser must be properlyvented or a de-rating factor should be applied to the 120-ampere riserrating. Note that solar de-rating will be a factor only for summer load-ing and when the temperature exceeds 100°F.

This analysis shows that the riser pole limits the rating of the total un-derground circuit. At 100 percent load factor and 20°C ambient soil, di-rect-buried 1/0 cable ampacity of 274 amperes would be reduced by57 percent and the 162-ampere rating of cable in duct would be re-duced by 26 percent.

75% LF = 1.08 × 264 = 285 amperes50% LF = 1.16 × 264 = 306 amperes

Ampacity = 264 amperes at 100% load factor

= 1.037790 – 2090 – 25

156 amperes at 100% LF162 amperes at 75% LF (1.04 × 156)167 amperes at 50% LF (1.07 × 156)

Load Factor Direct Buried In Duct

100% 274 162

75% 298 168

50% 318 173

Ampacity =120 amperes at 40°C ambient and 100% LF

satisfactory for many types of soils. Unless thesoil properties and moisture content of a partic-ular installation are known, ampacity valuesshould be chosen from the “Amperes at 60°C”

columns, rather than those from the “Amperes”columns.

The three following examples illustrate theconcepts covered in this section.

As most single-phase circuits do not operate at 100 percent load fac-tor, determine the cable rating at 75 percent and 50 percent load fac-tor using the correction factors contained in Table 4.1:

The cooperative’s standard installation practice for road crossings is topull cable through conduit to speed cable change out if it fails. FromTable 4.1, the cable rating in direct-buried conduit is as follows:

It is assumed that the under-road section is long enough so there is noadditional cooling effect from the direct-buried cable on either side ofthe road.


4EXAMPLE 4.3: Emergency Overload Rating Cable in Protective Riser.

From previous load studies and demand measurements, the engineerknows that the load factor on his heavily loaded loop-feed circuits hasnever exceeded 75 percent. Given this fact, determine the emergencyoverload rating of the cable in the protective riser.

The conditions necessary to produce maximum current at a riser in-clude a loop-feed installation with the open point near the center of theloop and a cable failure near the opposite riser pole. These conditionsare relatively rare and represent an emergency situation that shouldlast for only a short time.

From Table 4.10, the conduit-in-air correction factor for an emergencyoverload conductor temperature of 130°C is 1.27 for an ambient

Emergency Riser Rating = 1.27 × 120 = 152 amperes

air temperature of 40°C. Therefore,

Because the cable is in a riser, no ampacity increase is allowed for 75percent load factor. Comparing this value with the 75 percent load fac-tor ampacity of the direct-buried and buried duct sections of the cablerun shows the duct portion is overloaded by 10 percent and the direct-buried sections are well within their ratings. Note that, for simple ra-dial feed circuits, the 90°C conductor ampacity rating of a riser shouldnever be exceeded.

EXAMPLE 4.4: Three-Phase Substation Exit Ampacity.

The same cooperative from Example 4.2 is planning to install a new12/16/20-MVA transformer in an existing substation. The addition isneeded to support expected load growth in the area and will replacean existing overloaded transformer. Four 12.47-kV feeders will beneeded. A 600-ampere recloser will protect each feeder. Because ofcongestion around the substation, four underground circuit exits thatwill terminate on two double-circuit riser poles are planned. The cablefor each underground exit must be sized to carry, under emergencyratings, the full load of one other circuit in case of a cable failure. Findthe appropriate size cable for the application.

Assume two three-phase circuits to a riser pole will be installed in twoseparate trenches. Each of the circuits to a given riser pole will provideemergency backup for the other. Each circuit will be in a single conduitin trefoil configuration, similar to configuration 3 of Figure 4.10. Maxi-mum conductor temperature will be limited to 90°C, soil thermal re-sistivity (rho) will be 90°C-cm/watt, and load factor will be 75 percent.

Maximum feeder loading assuming balanced feeders is approximately260 amperes. For the contingency condition of a failed cable, the max-imum short-time loading would be as follows:

The smallest cable size to meet the emergency overload current canbe found by first calculating the emergency correction factor for a con-ductor temperature of 130°C from Equation 4.4,

2 × 260 = 520 amperes

I '130 = × I90 = 1.198 × I90×130 – 2590 – 25

228.1 + 90228.1 + 130

For aluminum conductor,

I '130 = × I90 = 1.199 × I90×130 – 2590 – 25

234.5 + 90234.5 + 130

For copper conductor,

For Copper For Aluminum

500 kcmil 750 kcmil

439 × 1.2 = 527 amperes 437 × 1.2 = 524 amperes

Find a copper or aluminum cable from the ampacity tables in Appen-dix G for configuration 3 (single direct-buried conduit with three con-ductors) whose 90°C, 75 percent load factor rating when multipliedby 1.2 gives a value approximating 520 amperes (520 ÷ 1.2 = 433amperes). Cable ampacity ratings at 130°C conductor temperature areas follows:

Continued

142 – Sect ion 4

SECONDARY CABLE AMPACITYSecondary cables carry powerat utilization voltage level fromthe pad-mounted distributiontransformer low-voltage termi-nals to the service entrancepoint for each consumer. Themany conditions that affect theampacity of primary cable alsoapply to secondary cable installations. Amongthese conditions are the following:

• Maximum insulation operating temperature,• Conductor resistance,• Load factor,• Soil thermal resistivity,

4EXAMPLE 4.4: Three-Phase Substation Exit Ampacity. (cont.)

The emergency rating of both cables is greater than the 520-ampereemergency requirement. Even if the two conduits had been installedwithin 18” of each other (Configuration 5), the single circuit in a trenchampacity table is the correct configuration to use in this instance be-cause only one circuit will be energized during the emergency condition.

Next, the riser pole current rating should be checked to see if it will limitthe cable application. From Tables 4.6 and 4.7, the corresponding riserpole ratings are 409 amperes for copper and 411 amperes for aluminum.Both values are less than their respective buried conduit ratings (439copper and 437 aluminum). The riser cable 130°C emergency overloadrating at 40°C ambient air temperature can be found from Table 4.10.

Because the riser emergency rating is less than the buried conduitemergency rating, the riser cable section is the limiting element in theapplication.

The application is a valid emergency situation if it is understood theoverload condition will not exceed 100 hours in any 12-month periodor 500 hours over the planned life of the installation. This substationexit application is covered by standards because it is an unplannedoutage of a nearby cable.

Note that the riser must be open at the top and vented at the bottomto provide additional ampacity above the values given in the tables andto compensate for any de-rating caused by solar heating.

500 kcmil copper = 1.27 × 411 = 522 amperes750 kcmil aluminum = 1.27 × 409 = 520 amperes

Equation 4.5

where: kVA1φ = Total load for single-phase applicationskVA3φ = Total load for three-phase applicationskVL-L = Voltage line-to-line, in thousands of voltsI1φ = Single-phase current, in amperesI3φ = Three-phase current, in amperes

Single-Phase: I1φ =

Three-Phase: I3φ =kVA3φ

3 kVL-L

kVA1φ

kVL-L

• Ambient soil temperature,and

• Installation configuration: Direct buried In duct.

The appropriate secondarycable size is selected based onthe amount of load the cablewill serve. In a later subsection

titled Transformer Sizing for Single-Phase Trans-formers for New Residential Loads, a procedure isoutlined to determine the appropriate transformersize on the basis of the number of connected loadsand the diversified demands of each load. Oncethe expected load and secondary operating volt-age are known, the required ampacity for bal-anced loads can be determined from Equation 4.5.

Once the secondary current load is calculatedfrom Equation 4.5, ampacity tables can be consult-ed to select the proper cable size. Table 4.11 givesthe allowable thermal loading for the most com-mon secondary cable sizes in a buried environ-ment for 100 percent load factor, 90°C maximumconductor temperature, 20°C ambient soil temper-ature, and 90°C-cm/watt soil thermal resistivity.

After a secondary cable size is selected fromampacity tables, the application must be checkedto ensure that voltage drop and flicker are withinacceptable limits. These calculations are coveredin detail in Appendix B.

Primary and secondary

cable ampacities are

affected by the

same conditions.


4Phase Conductors Neutral Dimensions (mils) Ampacity (amps)*

Size Insul. Size Insul. Single- Wt. per In(AWG Thick. (AWG Thick. Phase Complete 1,000 ft Direct Buried

Code Word or kcmil) Strand (mils) or kcmil) Strand. (mils) Cond. Cable (lb.) Burial Conduit

DUPLEX

Bard 8 7 60 8 7 60 262 524 76 70 55

Claflin 6 7 60 6 7 60 299 598 104 95 70

Delgado 4 7 60 4 7 60 345 690 138 125 90

TRIPLEX

Vassar 4 7 60 4 7 60 345 745 191 125 90

Stephens 2 7 60 4 7 60 403 870 249 165 120

Ramapo 2 7 60 2 7 60 403 870 278 165 120

Brenau 1/0 19 80 2 7 60 512 1,106 387 215 160

Bergen 1/0 19 80 1/0 19 80 512 1,106 441 215 160

Converse 2/0 19 80 1 19 80 555 1,199 478 245 180

Hunter 2/0 19 80 2/0 19 80 555 1,199 535 245 180

Hollins 3/0 19 80 1/0 19 80 603 1,302 581 280 205

Rockland 3/0 19 80 3/0 19 80 603 1,302 651 280 205

Sweetbriar 4/0 19 80 2/0 19 80 658 1,421 709 315 240

Monmouth 4/0 19 80 4/0 19 80 658 1,421 796 315 240

Pratt 250 37 95 3/0 19 80 732 1,581 853 345 265

Wesleyan 350 37 95 4/0 19 80 831 1,795 1,118 415 320

Holyoke 500 37 95 300 37 95 956 2,065 1,544 495 395

Rider 500 37 95 350 37 95 956 2,069 1,597 495 395

QUADRAPLEX

Tulsa 4 7 60 4 7 60 345 833 255 120 85

Dyke 2 7 60 4 7 60 403 973 342 155 115

Wittenberg 2 7 60 2 7 60 403 973 371 155 115

Notre Dame 1/0 19 80 2 7 80 512 1,236 534 200 150

Purdue 1/0 19 80 1/0 19 80 512 1,236 589 200 150

Syracuse 2/0 19 80 1 19 80 555 1,340 657 225 170

Lafayette 2/0 19 80 2/0 19 80 555 1,340 713 225 170

TABLE 4.11: Typical Ampacities for Various Sizes and Types of 600-Volt Secondary UD Cable—StrandedAluminum Conductors.

Continued

144 – Sect ion 4

4Phase Conductors Neutral Dimensions (mils) Ampacity (amps)*

Size Insul. Size Insul. Single- Wt. per In(AWG Thick. (AWG Thick. Phase Complete 1,000 ft Direct Buried

Code Word or kcmil) Strand (mils) or kcmil) Strand. (mils) Cond. Cable (lb.) Burial Conduit

QUADRAPLEX (cont.)

Swarthmore 3/0 19 80 1/0 19 80 603 1,456 798 250 195

Davidson 3/0 19 80 3/0 19 80 603 1,456 868 250 195

Wake Forest 4/0 19 80 2/0 19 80 658 1,588 974 290 225

Earlham 4/0 19 80 4/0 19 80 658 1,588 1,061 290 225

Slippery Rock 350 37 95 4/0 19 80 831 2,006 1,544 385 305

*Ampacity: 90°C conductor temperature, 20°C ambient temperature, rho 90, 100% load factorNote. Excerpted from Southwire Product Catalog, Section 16, pages 2, 3, and 4, 2003.

TABLE 4.11: Typical Ampacities for Various Sizes and Types of 600-Volt Secondary UD Cable—StrandedAluminum Conductors. (cont.)

PAD-MOUNTED TRANSFORMERSThe distribution transformer is an essential com-ponent of the underground distribution system.Besides providing transformation from primaryto secondary voltages, it provides an area forprimary and secondary cable terminations,switching and surge protection equipment, andovercurrent protective devices, all housed withinthe transformer enclosure. Because of increasedUD usage, special pad-mounted distributiontransformers were developed with the abovefeatures. The term pad comes from the trans-formers usually being locatedon concrete slabs or pads(Fink and Beaty, 1987).

Figure 4.11 shows a typicalsingle-phase, pad-mountedtransformer with its coveropen. Two primary bushingwells are shown at the upperleft for use with load-break el-bows. This dead-front configu-ration allows a low-height design to be used inresidential areas and provides greater safety foroperating personnel. The secondary 240/120-volt bushings with copper studs are shown onthe right.

LOADING FOR NORMAL LIFE EXPECTANCYIn service, a transformer is not loaded continu-ously at rated kVA and at a constant temperature.Instead, it goes through a daily load cycle with ashort-time peak load occurring usually during thehottest part of the day. A varying load poseschallenges in optimizing a transformer’s full-loadcapability without shortening its useful life. Thecapability of pad-mounted distribution transform-ers to carry loads under conditions other thanthose used to establish nameplate ratings will bereviewed later in this section. Because loading

guides are based on the aver-age winding temperature riseabove ambient, the load-carry-ing ability of a pole-type trans-former is basically the same asthat of a pad-mounted trans-former. Standards make nodistinction between the two.Additional information onloading distribution transform-

ers can be found in ANSI/IEEE Standard C57.91.Standards assign a distribution transformer a

rated output that is expressed in kVA. The trans-former is designed to carry this rated load contin-uously over its expected lifetime at an ambient

Pad-MountedTransformerSizing

Loading considerations

for pole- and pad-

mounted transformers

are the same.


temperature of 30°C (86°F), without exceedingan average winding tempera-ture rise of 65°C. Under theseconditions, insulation deterio-ration and transformer loss oflife are considered normal. In-dustry experience has shownthat normal life expectancyunder these conditions shouldbe at least 20 years.

Heat gain within a transformer is caused byno-load and winding losses. Keeping the temper-ature rise of the windings below 65°C depends

4

FIGURE 4.11: Typical Dead-Front, Single-Phase, Pad-MountedTransformer

on the ability to transfer internal heat to the at-mosphere. The capability of the cooling systemto rid the transformer of heat depends mainly onthe temperature differential between the tankand the ambient air because most pad-mountedtransformers do not have forced-air cooling. Theambient air temperature is the most important el-ement in determining how much load a trans-former can carry because the temperature rise ofthe insulation for any load is added to the ambi-ent temperature to determine the actual operat-ing temperature of the transformer.

To select daily peak loads from publishedloading guides, the engineer must predict whatthe temperature will be during the peaks. Theprobable ambient temperature for any futuremonth can be estimated from historical weatherdata from the cooperative’s service area.

ANSI/IEEE C57.91 gives two methods to pre-dict temperature for the month involved. One isused to select loads for normal life expectancyand uses average daily temperature (defined asthe average of all daily highs and all daily lows)for the month, averaged for several years. Theother uses the maximum daily temperature (de-fined by the standard as the average of the highand low of the hottest day) for the chosenmonth, averaged over many years.

Whenever these two methods are used, it isunderstood that, during any one day, the maxi-mum temperature may exceed the average val-ues found above. To be conservative, thesetemperatures should be increased by 5°C be-cause insulation does not recover fully after it isoverheated. The maximum temperature over a24-hour period should not exceed the average

temperature by more than10°C, which provides an ade-quate safety margin. Accordingto the above factors, the esti-mated temperature should notbe exceeded for more than afew days per month; however,if it is, the transformer will notbe adversely affected by the

small incremental loss of life.Standard loading tables give ambient tempera-

tures in 10°C intervals. Estimating peak loads

Ambient temperature

and load factor set

transformer loading.

146 – Sect ion 4

between the given tempera-tures in a table is allowed.Peak loads obtained in thisway are accurate enough forthe ambient temperatures de-rived from the above example.However, extrapolation beyondthe range of values shown inthe tables is not recommended.

The engineer can perform the same type ofambient temperature analysis for winter monthsif the transformers are experiencing winterpeaks. The standard does not deal with the elec-tric heating load that will be greatest during thecoldest days of the month, so results will beconservative. When the ambient temperaturestudy produces a result below 0°C, the loadinglimits from the 0°C columns should be used in-stead of extrapolation.

Other items that can affectpad-mounted transformercooling are altitude and tankfinish. At higher altitudes, theair is not as dense; this de-creases cooling efficiency.Above 3,300 feet, a trans-former kVA rating should bereduced approximately 0.4

percent for each 330 feet of additional altitude.The ability of a transformer to radiate heat is

affected by its paint finish. Some metal flakepaints, like aluminum, reflect heat from directsunlight quite effectively; however, they do notallow heat to escape as efficiently. Because mosttransformer heat is produced internally, metal-based paints actually increase the temperaturerise in most instances (Lee 1973). The subject ofpaint finish is mentioned only in connection

4EXAMPLE 4.5: Average Daily Temperature Selection for a Summer-Peaking Utility.

The procedure to select the averagedaily temperature for loading distribu-tion transformers is shown in this ex-ample. ABC Cooperative is located inthe Southeast. As part of an opera-tions review process, the manager andengineer decided to establish a formalprocedure to select the proper sizepad-mounted distribution transformersfor an expected surge in undergroundinstallations in its service area.

The first step in determining the maximum load eachtransformer can carry is to select an approximate am-bient temperature that would be expected on the peakday. This summer peaking cooperative obtained the av-erage July and August temperatures for the previous10 years from the Weather Bureau of the U.S. Depart-ment of Commerce.

Table 4.12 averages the temperatures found.

Adding 5°C to the average, as recommended by ANSI/IEEE C57.91, gives 27.1°C + 5°C = 32.1°C, which nor-mally should be used for any transformer loading studies.

The standard also specifies that the maximum temper-ature over a 24-hour period should not exceed the

average temperature selected by more than 10°C. Thus,the maximum temperature should not exceed 27.1°C+10°C = 37.1°C (98.8°F). However, the engineer foundthat, in the hot summer of 1987, on many days the tem-perature reached 100°F (37.8°C) or more. If an actualmaximum daily temperature in recent memory has beengreater than 10°C above the maximum temperature av-eraged for the previous 10 years, it is suggested thatthat higher temperature be used in your calculations. Toallow for the probability of 100°F days occurring, the en-gineer increased the 32.1°C average temperature se-lected previously by 0.7°C—the difference between thecalculated plus-10°C maximum (37.1°C) and the actualhigh temperature (37.8°C)—thus using 32.8°C as thetemperature to be used in the study.

Month Average (°F) Average (°C)

July 80.6 27.0

August 81.0 27.2

Average of Temperatures 80.8 27.1

TABLE 4.12: Average Temperatures for July and AugustAveraged for the Previous 10 Years.

Altitude, tank finish,

and ventilation affect

pad-mounted

transformer cooling.


with refinishing transformers in the field. Theengineer should be careful that the paint se-lected is a standard pad-mounted transformerfinish with good radiating properties.

Proper ventilation should always be consid-ered when siting a pad-mounted transformerand after installation to allow the cooling systemto function at peak efficiency. Care should betaken to allow for air to circulate freely aroundthe unit at all times.

LOAD CHARACTERISTICSThe normal load durationcurve of a typical pad-mounted transformer withmore than one service con-nected to it consists of a rela-tively low load during most ofthe day, with one peak load

4

FIGURE 4.12: Actual Load Cycle and Equivalent Load Cycle.

12 6AM

12

70% Initial Load

Actual Load

140%Peak Load

1 Hour

Time (Hours)

LoadasPercentageof

TransformerRating

6PM

120

50

100

150

12 6AM

12

Transformer Rating

50% Initial Load

137%Peak Load

2 Hours

Time (Hours)

LoadasPercentageof

TransformerRating

6PM

120

50

100

150

FIGURE 4.13: Thermal Equivalent Load Cycle.

lasting from a few minutes to a few hours. Asimilar cycle is repeated every 24 hours. Thischaracteristic allows the transformer to be oper-ated at loads exceeding its continuous kVA rat-ing during short peaks. Two main characteristicsof the transformer permit the overload to be car-ried without decreasing normal life expectancy.

The first characteristic is the thermal time con-stant, which ensures that the internal oil tempera-ture increases slowly after a rapid change in load.This fact is important because of the limitation that

the winding hot-spot tempera-ture places on the ability of thetransformer to carry an overloadwithout insulation damage. Fora step change in load, the con-ductor temperature at the hottestspot in the winding increases toits maximum value very quick-ly. However, hot-spot and totalconductor temperature are held

down until the thermal time constant is exceed-ed, which could be three to 10 hours, dependingon preload conditions. Pad-mounted transform-ers are now designed to operate continuously ata winding hot-spot temperature of 110°C.

The second characteristic is the thermal agingof transformer insulation. Hot-spot temperaturesabove 110°C can be carried for short times with-out shortening the expected life of the trans-former, as long as they are followed by longerperiods of operation below 110°C. Elevated tem-peratures do not cause insulation failure, butonly increase the rate of its deterioration whenthey are prolonged.

It follows that a pad-mounted transformer light-ly loaded before a peak will have a lower hot-spottemperature than one carrying full load beforethe same peak. Therefore, the shape of the loadcurve over a 24-hour period can greatly affectwhat peak load may be carried by a transformer.

If a daily load duration curve for a singletransformer was plotted from data collected byan interval demand recorder, it would be similarto the curve in Figure 4.12.

To use loading guides provided in the stan-dard, change the actual load duration curve intoa thermally equivalent, simple rectangular loadcycle as shown in Figure 4.13.

Short peak overloads

can be carried

without loss of

transformer life.

148 – Sect ion 4

Estimating the duration ofthe peak has considerable in-fluence over the rms magni-tude of the peak load. Cautionshould be used to not overes-timate on-peak time. If the du-ration is overestimated, therms peak load may be far

below the maximum peak demand.After the equivalent peak load has been deter-

mined, a loading guide—such as the one inTable 4.13—may be used to pick a transformersize to supply the expected daily loading. It canalso be used to determine whether or not an ex-isting transformer will supply the listed dailypeak loads and a 20-year minimum life ex-pectancy. The ambient temperature to use in theloading guide is the average daily temperaturedetermined using the procedure outlined in aprevious subsection, Loading for Normal LifeExpectancy.

The preload level given in the tables is basedon the transformer nameplate rating and is not apercentage of peak load. Example 4.6 illustratesthis principle.

Note that even under 0°C ambient conditionsthat might apply for winter-peaking studies incold-climate areas, a maximum loading above

4

Equation 4.6

where: L1, L2, etc. = Average load by inspection for each1-hour interval of the 12-hour periodpreceding the peak transformer load

Equivalent Initial Load = 0.29 L12 + L22 + L32 + ... L122

Equation 4.7

where: L1, L2, . . . = The various load steps as a percentage,per unit, actual kVA, or current

t1, t2, . . . = Respective durations of these loads

Equivalent Peak Load =L12 t1 + L22 t2 + L32 t3 + ...Ln2 tn

t1 + t2 + t3 + ...tn

Continuous Equivalent Load as Percentage of Rated kVA Preceding Peak Load50% 75% 90%

Ambient (°C) Ambient (°C) Ambient (°C)

0 10 20 30 40 50 0 10 20 30 40 50 0 10 20 30 40

1 2.52 2.39 2.26 2.12 1.96 1.79 2.40 2.26 2.12 1.96 1.77 1.49 2.31 2.16 2.02 1.82 1.43

2 2.15 2.03 1.91 1.79 1.65 1.50 2.06 1.94 1.82 1.68 1.52 1.26 2.00 1.87 1.74 1.57 1.26

4 1.82 1.72 1.61 1.50 1.38 1.25 1.77 1.66 1.56 1.44 1.30 1.09 1.73 1.62 1.50 1.36 1.13

8 1.57 1.48 1.39 1.28 1.18 1.05 1.55 1.46 1.36 1.25 1.13 0.96 1.53 1.44 1.33 1.21 1.02

24 1.36 1.27 1.18 1.08 0.97 0.86 1.36 1.27 1.17 1.07 0.97 0.84 1.35 1.26 1.16 1.07 0.95

Note. For transformer operation above 50°C or below 0°C, contact manufacturer. Peak loads shown assume 0.0137% per day loss of life for normal lifeexpectancy. The ambient temperature to use in the table is the average temperature over a 24-hour period, with the maximum temperature notexceeding the average temperature by more than 10°C.

Excerpted from Table 5, page 20, ANSI/IEEE C57.91-1981.

TABLE 4.13: Daily Peak Loads Per Unit of Nameplate Rating for Self-Cooled Oil-Immersed Transformers toGive Minimum 20-Year Life Expectancy.

This conversion is done byderiving the values for the ini-tial load and the peak load.These values may be approxi-mated by the formulas shownin Equations 4.6 and 4.7(ANSI/IEEE C57.91-1981).

Equation 4.7 shows the for-mula for the equivalent peak load.

Consider preload

conditions when

loading transformers.

PeakLoadTime inHours


1.8 pu cannot be justified from the tables if pre-load conditions are 50 percent or more of peakload. This maximum exists because the 90 per-cent preload level is the largest tabulated. Thisanalysis shows that some of the very large per-unit values shown in ANSI/IEEE Standard C57.91tables are not particularly practical.

It is not practical or economical to conduct anin-depth study on every transformer suspectedof being overloaded. In fact, for small transform-ers, the cost of an individual detailed analysiscould exceed the price of the transformer. How-ever, if an overload is expected on a large three-phase, pad-mounted transformer, investigationwould obviously be warranted.

Loading levels applied to transformers shouldbe kept within those of Standard C57.91-1981.Doing so protects not only the transformerwindings but also ancillary components on thetransformer. Manufacturers design items such asbushings, internal connections,and fuse protection assumingthat the transformer loadingwill not exceed StandardC57.91-1981 levels. This coor-dinated design is noted inANSI/IEEE C57.12.00-2000,Section 4.2, and C57.91-1995,Section 8.2.1.

4EXAMPLE 4.6: Selection of Maximun Permissible TransformerPer-Unit Loading.

Load-pattern studies of pad-mounted transformers in a certain area revealed that typ-ical 12-hour preload levels were 50 percent of peak load levels. The peak loads hada duration of two hours and the ambient temperature for the area was calculated at30°C. The engineer needs to estimate the maximum permissible per-unit (pu) load-ing for the transformers to maintain normal life expectancy.

The per-unit loading shown in Table 4.13 under 50 percent preload, 30°C ambient,and two-hour peak duration is 1.79 pu. However, if this loading level is permitted, thepreload level will become 0.5 × 1.79, or 0.9 of the transformer nameplate rating.Therefore, conservatism requires that the engineer take the per-unit loading fromthe tabulated figures under 90 percent preload conditions, which will lead to a max-imum loading of 1.57 pu. This change shifts the preload level to about 79 percent.A load somewhat higher than 1.57 pu is permissible. However, it should not be higherthan the 1.68 pu figure shown under the 75 percent preload conditions. By interpo-lation, the engineer can estimate a final result of 1.63 pu loading.

If a transformer is being severely overloadedfor extended periods, its life expectancy is beingshortened and excessive conductor losses willbe increasing operating costs. These conditionscan be allowed during emergencies, but, undermost conditions, they should not be continuedfor a sustained period of time.

The NRECA Loss Management Manual thor-oughly covers the issue of loss-optimal loading ofdistribution transformers. Engineers should defi-nitely consult this manual before establishing finalpolicies on loading pad-mounted transformers.

TRANSFORMER SIZING FORSINGLE-PHASE TRANSFORMERSFOR NEW RESIDENTIAL LOADSTransformer loading is further complicated be-cause loading levels are difficult to estimate fortransformers serving residential consumers. Engi-neers have tried different methods to estimate thepeak kVA load of a group of single-family livingunits. However, many varying circumstances,such as the sizes and types of electrical appli-ances used, cause the load-estimating procedureto become somewhat complicated. Table 4.14shows a sample load-estimating guide for asoutheastern utility. Cooperative engineers shouldnot use it to estimate transformer loading ontheir own systems because diversity factors,loads, and demands are different for every util-ity’s service area. For example, the resistanceheating diversity factors in this method apply toa semicoastal southern climate and may not ac-curately reflect conditions in other climates.Also, the air conditioning efficiencies in yourarea may differ from those used in the develop-ment of this chart. The table is included as anexample to demonstrate that similar tableswould be useful or can be developed from mar-keting and load research data.

Table 4.14 can be used toestimate the diversified de-mand for a group of totallyelectric homes. The first step isto determine the number ofconsumers connected to thetransformer and select the cor-responding diversity factorsfrom Chart 1. The second step

Use a loading

guide developed

for your particular

service area.

150 – Sect ion 4

is to find the base kVA load for one consumerusing Chart 2. The chart row labeled “TE” givesthe base total electric load related to house size.The “A/C” row gives the air-conditioning loadfor the air-conditioner sizes shown. The equiva-lent kVA demands for various resistance stripheaters are listed in Chart 3. To find the load fora group of consumers, multiply the kVA valuesfrom Charts 2 and 3 by the appropriate diversity

factors from Chart 1. Diversity factors dependon the number of consumers in the group. Todetermine whether transformer size is set by thesummer or winter load, do the calculation withair-conditioner load and then with resistanceheat load.

Equation 4.8 gives the total load (LX) for Xidentical consumers.

Example 4.7 clarifies the procedure.

4

Chart 3

Equivalent kVA Demand for HousesWith Resistance Heat

kW Rating kVA Demand

5.0 5.0

7.5 6.5

10.0 8.0

15.0 10.5

20.0 14.0

Chart 2

Standard House Loads (kVA)

Typical Residence Size (Square Feet)

Type of Load 1,500 2–3,000 5,000+

TE 4.3 kVA 5.7 kVA 7.5 kVA

Typical Air Conditioner Size (Tons)

Type of Load 3 4 5

A/C 3.8 kVA 5.1 kVA 6.3 kVA

TABLE 4.14: Application of Single-Phase Distribution Transformers to Serve ResidentialConsumers—Sample Loading Guide.

Chart 1

Diversity Factor D

Number ofConsumers Total Electric Air Conditioningin Group (X) (TE) (A/C)

1 1.00 1.00

2 0.85 0.85

3 0.74 0.83

4 0.66 0.80

5 0.61 0.77

6 0.57 0.75

7 0.54 0.73

8 0.52 0.72

9 0.50 0.71

10 0.49 0.70

11 0.47 0.70

12 0.46 0.69

13 0.45 0.69

14 0.43 0.68

15 0.42 0.68

16 0.41 0.67

17 0.39 0.67

18 0.38 0.66

19 0.38 0.66

20 0.37 0.65

Note. Values in the charts were excerpted fromthe South Carolina Public Service Authority(Santee Cooper) Distribution EngineeringReference Manual dated February 2, 1987.

Diversity, Load, and Demand Charts


Example 4.7 assumes the transformer full-loadrating, corrected for ambient temperature, canbe up to 140 percent of its summer loading. Theability to carry more load in the winter is justifiedbecause the heating load factor is much lowerthan the cooling load factor for the assumedtransformer service area. Cooler ambient temper-ature in winter also increases transformer loadingcapabilities. Each cooperative must set its ownpercentage loading limit based on experience.

Before the transformer is installed, its sizeshould be checked to see if it meets cooperativevoltage drop and flicker criteria. These calcula-tions are covered in Appendix B, “Transformerand Secondary Voltage Drop.”

4Equation 4.8

LXSummer = X[(TE Load)(DX(TE)) + (A/C Load)(DX(A/C))]kVALXWinter = X[(TE Load)(DX(TE)) + (Heat Load)(DX(A/C))]kVA

where: LX = Total load for X identical consumers, in kVAX = Total consumers in groupTE Load = Base total electric house load from Chart 2, in kVADX(TE) = Diversity factor D for X consumers from Chart 1,

TE columnA/C Load = Base air-conditioner load from Chart 2, in kVAHeat Load = Base resistance heat load from Chart 3, in kVADX(A/C) = Diversity factor D for X consumers from Chart 1,

A/C column

EXAMPLE 4.7: Pad-Mounted Transformer Sizing for New UD Residential Consumers.

Assume four totally electric, 1,500-sq.-ft. homes are to be fed fromthe secondary of a pad-mounted transformer in a new subdivision. Allhomes have identical electrical appliances, three-ton (36,000-Btu) airconditioners, and 7.5-kW resistance heaters. Select the transformersize that will serve the summer and winter loads and has a 20-year lifeexpectancy. Pad-mounted transformers to choose from are rated25, 37.5, and 50 kVA.

First, select the diversity factors from Chart 1:

Second, choose the base TE load and A/C load for a single house fromChart 2:

From Equation 4.8, the total summer load is 23.52 kVA, as calculated:

A 25-kVA transformer is the proper size to choose, as no new houseswill be added to the transformer.

The total winter load is calculated the same way by replacing the air-conditioning load with the strip heater load from Chart 3. The A/C

diversity factor is applied to the heating load in this instance. Becausethe ambient temperature will be lower in the winter, it is assumed thetransformer will carry up to 140 percent of its summer peak load forshort periods without undue loss of life.

For the winter peak, the TE load component of the total load is thesame as before:

The 7.5-kW strip heating component of total demand is then

Total winter diversified demand is equal to

The ratio of winter to summer load is then

Because the ratio is below 140 percent, the transformer size will be setby the 23.52-kVA summer load. The 25-kVA unit is still the proper trans-former to install. (Note: Keep in mind this example is based on amethodology used by a southeastern U.S. utility and should be modi-fied for use in other climates.)

X = 4 consumers in groupsD4(TE) = 0.66D4(A/C) = 0.80

TE Load = 4.3 kVAA/C Load = 3.8 kVA

TE Load = (4)(4.3)(0.66) = 11.35 kVA

4(6.5)(0.8) = 20.8 kVA

Winter L4 = 11.35 + 20.8 = 32.15 kVA

= 137%Ratio =32.1523.52

Summer L4 = 4 [(4.3)(0.66) + (3.8)(0.80)] =4[2.84 + 3.04] = 23.52 kVA

152 – Sect ion 4

Another important concern is initial loadingversus future loading when load growth is expect-ed. For many UD areas, significant load growth isnot expected for individual transformers becausethe number of living units per transformer is setin the development plans. The modern trend inhousing construction is to install all heavy appli-ances and heating, ventilating, and air-condition-ing (HVAC) equipment in a dwelling before ini-tial occupancy, so any growth beyond the initiallevel is expected to be insignificant.

Even when engineers expect load growth,they seldom accurately know the rate of growth.Although complicated formulas exist for eco-nomic sizing of transformers based on loadgrowth, use of these formulas is meaningless ifthe growth rate is not accurately known. A sim-ple procedure is recommended, such as sizingthe transformer for the load that is estimated tobe present 10 years in the future.

TRANSFORMER SIZING FOR THREE-PHASETRANSFORMERS FOR NEW COMMERCIALAND INDUSTRIAL LOADSThree-phase transformers—required to renderservice to commercial and industrial con-sumers—represent a significant investment forthe average cooperative. As such, care shouldbe taken in selecting transformers sized to mini-mize cost and losses, while providing reliableservice.

Sizing transformers for these type installationsis not an exact science and requires sound judg-ment and previous experience, similar to thephilosophy involved in sizing single-phase trans-formers. Local geographical and climatologicalconditions must be considered, as they play asignificant role in sizing equipment. This subsec-tion presents three generally accepted methodsof sizing transformers that most cooperativesand utilities have used over the years:

1. Previous demands on similar loads,2. Watts-per-square foot demand factors, and3. Diversified connected load analysis.

It is suggested that an analysis be made usingall three methods, if possible, as a crosscheck tovalidate the final selection of a properly sized

4unit. Further analysis using both knowledge ofspecific types of loads and experience anticipat-ing the likelihood of growth in consumer de-mand is recommended.

Method I: Previous Demandson Similar ConsumersMany commercial establishments are part of largecompany chains that establish new facilities (orfranchises) based on similar building footprints,using the same makeup of electrical devices.Convenience stores, supermarkets, drug stores,fast-food restaurants, and discount departmentstores, for example, have branch stores that re-sult in very similar demands, provided geograph-ical influences are similar. The only differencesin some of these installations are whether or notnatural gas, propane, or other heat source is ei-ther available or economically feasible. A startingpoint (or a double check) in sizing transformersfor these type loads is to contact other coopera-tives (or IOUs) to obtain historical demand data(both summer and winter peaks) for similarstores of the same relative size. Care should betaken for loads greater than 300 to 400 kW, aseven similar stores can operate differently be-cause of local usage patterns. Care should alsobe taken to evaluate power factors of loads forlarger units, if such information is available frommeter readings. If power factor readings (or bothkW and kVAr readings) are available, then thetransformer size can be selected to account forpower factor by using either of the followingformulas:

Method II: Watts-Per-Square-Foot MethodElectrical demands for commercial and industrialbuildings can be analyzed by evaluating typicalwatts-per-square-foot factors that have been estab-lished by utilities and design professionals overthe years. Although these factors can vary overdifferent geographical areas of the country as aresult of climate factors and building practices,the basic values listed in Table 4.15 are typical ofmost areas of the continental United States.

1. kVA2 = kW2 + kVAr2

or kVA =

or kVA =

2. Power Factor = kWkVA

kWPowerFactor

kW2 + kVAr2


Keep in mind that these factors are typical ofloads analyzed in many areas of the country andcan vary somewhat. They are a good approxi-mation to be used as a double check of otheranalytical methods. Also remember to convertthe calculated kW to kVA using power factor in-formation. If the developer of the new facilitycannot provide valid power factor information,Table 4.16 will assist in this effort. Again, thesepower factor values are typical of a number ofcases sampled.

Method III: Summation of DiversifiedConnected LoadsThe most analytical method available to predictthe actual demand of a new consumer’s installa-tion is to total the individual connected loadsand apply diversity factors to multiple quantitiesof similar loads, and to the different types ofload, to predict the effective actual demand. Thephilosophy here is that not all connected loadswill operate simultaneously, as a result of cy-cling off and on by some automatic system (athermostat, for example), or as a result of theoperation inherent with the facility. It is impor-tant to gather all the connected load informationfrom a consumer, both the types of loads andthe quantities of similar electrical devices.

For example, a restaurant may have five roof-topair conditioner units, one for each of five zonesof the interior space. Further discussion with theconsumer may indicate use of a demand-sidemonitoring system that cycles the HVAC units, sono more than three units can run at any onetime. While this type of system will reduce thedemand at any given time to the load imposedby three units, the result may be an increase inthe customer’s load factor, which will tend to in-crease the required size of the transformer. Mul-tiple kitchen appliances may, as well, be used inshift operations, with only portions of the de-vices operating together. The more informationthat may be gathered about how electrical de-vices will be operated, the more accurately ananticipated demand can be calculated.

Following are other items to be taken into ac-count while accumulating electrical load data fordiversification:

4Watts per Square Foot*

Type Facility Winter Summer

Banks 9.2 6.3

Offices (less than 100,000 square feet) 10.0 8.3

Offices (more than 100,000 square feet) 7.7 6.4

Churches 9.7 6.2

Convenience Stores 13.0 12.7

Department Stores 6.9 5.6

Medical Clinics 11.3 8.6

Grocery Stores 10.1 10.4

Restaurants (fast-food) 45.8 41.5

Restaurants (fast-food/gas) 28.0 25.4

Restaurants (family) 27.3 21.9

Variety Stores 10.2 7.1

Schools 10.2 5.6

Motels 7.6 4.6

*All-electric, unless otherwise noted

TABLE 4.15: Typical Watts-Per-Square-Foot Factors forCommercial Buildings.

Type Facility Approximate Power Factor*

Restaurants 85%

Grocery Stores 85–90%

Office Buildings 90%

Retail Department Stores 90%

Residential Loads 95%

Lighting (HID) 95%

Motors That Operate at Full Load 80–85%

Motors That Operate at Less Than Full Load 50%

Sawmills 65%

Industrial Plants With Heavy Motor Load 65–70%

*If consumers have their own capacitors, higher values will result.

TABLE 4.16: Typical Electrical Load Power Factor Values.

154 – Sect ion 4

• The larger of heating or air conditioningshould be used, but not both.

• Do load controllers limit the quantity of anydevices running simultaneously?

• Do certain devices, such as dishwashers,operate only on off-peak times, such as at theend of a shift?

• How many portable appliances are plannedto be connected to convenience outlets?

• At what temperatures are refrigeration units tobe operated (e.g., coolers versus refrigerationunits versus deep freezers)?

• Are all exterior lights to come on throughphotosensitive control?

• Are water heaters multiple-element orload-controlled?

• Is any capacity currently listed on electricaldrawings as “spare” to be actually used in thenear future, or not at all?

Table 4.17 is a listing of typical types of loadsfor commercial/industrial applications, and the

4

Type of Equipment Demand Diversity Factor

Air Conditioning (less than 100 tons) 75%*Note: 1 ton = 1.5 kW

Air Conditioning (more than 100 tons) 75%*Note: 1 ton = 1.0 kW

Electric Heating 75%*

Computers 75%

Electric Cooking Appliances 35–40%

Lighting 70–80%

Miscellaneous 35%

Motors (less than 40 Hp)** 40%

Motors (more than 40 Hp)** 25%

Receptacle Load 10–15%

Refrigeration 60%

Water Heating 40–50%

“Spare”*** 0%

* Use the larger of heating or cooling, but not both.** Does not necessarily apply to industrial applications*** Consider “spare” only for specific needs.

TABLE 4.17: Typical Electrical Load Demand Diversity Factor Values.

typical diversity that is generally taken with re-spect to actual peak demands.

Table 4.18 is a typical listing of the electricalconnected loads associated with a new restaurantand how the loads can be tabulated to apply di-versity factors so that an anticipated peak demandcan be computed. Note that this demand shouldinclude the larger of heating or cooling loads, or,if necessary, a separate winter peak demand(with heating loads) and summer peak demand(with cooling loads) can be computed. Air han-dling units should be included in both listings.

Once the kVA demand is determined, decidehow large the transformer should be based onthe sizes available. Some decisions will be fairlyeasy, whereas others fall into a gray area whendemand could fit the top range of one size orthe bottom range of another.

The proper transformer size to be used for acalculated demand should be selected on thebasis of the transformer’s ability to withstandshort-term overload conditions, just as was dis-cussed with single-phase units on residential ap-plications. Consistent with the per-unit loadingguide discussed in this section (Table 4.13),three-phase transformers are capable of similarshort-term overloads (again, depending on theduration of the short-term peak and the relativeloading level of the transformer for the period oftime before the overloading condition).

Table 4.19 lists typical commercial/industrialconsumers and the duration typically found forshort-term overloads.

It is essential that information be obtainedfrom the consumer to substantiate these peakdurations or to determine that shorter or longeroverload periods should be used.

Once this information has been determined,the overload capacity of standard transformersizes should be reviewed, based on local ambi-ent temperature ranges. Listed in Table 4.20 is atypical cooperative’s overload factors, both sum-mer and winter, based on ANSI/IEEE C57.91-1981 Table 5 (Table 4.13 in this manual).

Note that the table lists both summer and win-ter overload factors, based on the typical ambienttemperatures of the winter and summer months.In Table 4.20, 10°C has been chosen for the winterambient, and 40°C has been chosen for the sum-mer ambient. As a method of practical conservative


4Item Unit Load Total Load Demand Total DemandNo. Load Description Quantity (kW) (kW) Diversity (kW)

1A Roof-Top Air Conditioning Units* 5 8.12 40.60 0.60 24.361B Heat Pump Strip Heaters ** 2 15.34 30.68 0.00 0.002 Baked Potato Oven 1 11.00 11.00 1.00 11.003 Potato Warmer 1 0.80 0.80 1.00 0.804 Heat Lamps 2 0.25 0.50 1.00 0.505 Warming Tray 1 1.50 1.50 1.00 1.506 Pie Safe 1 0.73 0.73 1.00 0.737 Coffee Maker 2 1.80 3.60 0.50 1.808 Soda Fountain 2 0.25 0.50 0.50 0.259 Ice Machine (Continuous Use) 1 1.70 1.70 1.00 1.7010 Ice Machine (Infrequent Use) 1 7.50 7.50 0.00 0.0011 Cooler 1 1.25 1.25 0.60 0.7512 Range Hood 1 0.90 0.90 1.00 0.9013 Freezer 1 1.09 1.09 0.60 0.6514 Cold Table 1 1.73 1.73 1.00 1.7315 Iced Tea Maker 2 1.52 3.03 0.50 1.5216 Microwave 1 1.50 1.50 0.00 0.0017 Warming Tray 1 1.59 1.59 1.00 1.5918 Toaster 1 2.83 2.83 1.00 2.8319 Refrigerator 1 1.08 1.08 0.60 0.6520 Cooler Table 1 0.76 0.76 0.60 0.4521 Steamer 2 0.75 1.50 0.50 0.7522 Dishwasher 1 8.61 8.61 1.00 8.6123 Prep Cooler 1 2.89 2.89 0.60 1.7324 Beverage Cooler 1 3.76 3.76 0.60 2.2525 Vegetable Cooler 1 3.76 3.76 0.60 2.2626 Outside Freezer 1 2.38 2.38 0.60 1.4327 Outside Lighting 2 0.40 0.80 1.00 0.8028 Outside Lighting 2 1.00 2.00 1.00 2.0029 Kitchen Lighting 20 0.16 3.20 1.00 3.2030 Dining Area Lighting 14 0.10 1.40 1.00 1.4031 Dining Area Lighting 6 0.13 0.75 1.00 0.7532 Heat Lamps/Warming Tray 1 1.56 1.56 1.00 1.5633 Coolers Under Bar 2 0.84 1.68 0.50 0.8434 Coolers Under Bar 1 0.42 0.42 0.50 0.2135 Television 1 0.45 0.45 1.00 0.4536 Neon Signs 4 0.05 0.20 1.00 0.2037 Video Game 1 0.16 0.16 1.00 0.1638 Roadway Sign 1 0.80 0.80 1.00 0.80

Total 151.17 83.10* Load controlled** Winter use only

TABLE 4.18: Estimated Electrical Demand (Summer) and Energy Consumption(Sample Family Restaurant).

156 – Sect ion 4

engineering practice, 90 percent prior loading hasbeen chosen for a safety factor. If the actual priorloading can be substantiated, then 75 percent or 50percent prior loading per-unit values could be used.

On the basis of these per-unit overload factors,the standard sizes of pad-mounted transformersin Table 4.21 can carry short-term overloads aslisted for respective winter and summer ambientconditions. Care should be taken to not under-estimate duration peaks and to apply properambient temperatures.

Sizing transformers is not an exact science.However, by using the guidelines in this section,along with gaining experience from the localambient conditions, one can become more effec-tive in sizing transformers and the process willbecome less confusing. Some of the main keysto sizing a transformer are the following:

• Understanding what affects a transformer’sloading capability (ambient temperature, loadcycles, etc.).

• Properly estimating the load (similar accounts,diversity, watts/square foot, etc.). Estimatingthe load is the largest factor in sizing a trans-former correctly. If this part is completedcorrectly, most of the work is done.

4Type of Business Time (Hours) Type of Business Time (Hours)

Fast Food 8 Restaurants 4

Grocery Stores 8 Hotels 4

Large Office Buildings 8 Small Office Buildings 4

Large Retail Stores 8 Small Retail Stores 4

Convenience Stores 8 Schools 4

Industrial Plants 24* Other Commercial 4

* The peak durations may be less, but use this number with the loading table unless thecustomer can provide information that is different.

TABLE 4.19: Estimated Peak Duration.

Summer Loading Winter LoadingPeak Duration Capability** Capability***

(Hours) (% of kVA Rating) (% of kVA Rating)

4 130% 166%

8 113% 146%

24 97% 127%

* From ANSI/IEEE C57.91-1981 Table 5, based on 90% prior loading** Based on 40°C ambient*** Based on 10°C ambient

TABLE 4.20: Transformer Loading Capability Table.*

4-Hour Peak Overload 8-Hour Peak Overload 24-Hour Peak OverloadTransformer Summer Winter Summer Winter Summer WinterNameplate Capacity** Capacity*** Capacity** Capacity*** Capacity** Capacity***

75 97.5 124.5 84.8 109.5 72.8 95.3

112 145.6 185.9 126.6 163.5 108.6 142.2

150 195.0 249.0 169.5 219.0 145.5 190.5

225 292.5 373.5 254.3 328.5 218.3 285.8

300 390.0 498.0 339.0 438.0 291.0 381.0

500 650.0 830.0 565.0 730.0 485.0 635.0

750**** 975.0 1,245.0 847.5 1,095.0 727.5 952.5

1,000**** 1,300.0 1,660.0 1,130.0 1,460.0 970.0 1,270.0

1,500**** 1,950.0 2,490.0 1,695.0 2,190.0 1,455.0 1,905.0

2,000**** 2,600.0 3,320.0 2,260.0 2,920.0 1,940.0 2,540.0

2,500**** 3,250.0 4,150.0 2,825.0 3,650.0 2,425.0 3,175.0

* Based on ANSI/IEEE C57.91-1981 Table 5, with 90% prior loading** Based on 40°C ambient*** Based on 10°C ambient**** Overload factors for some of these units may be limited as a result of fusing limitations at primary voltages of 12.5/7.2 kV (or less).

TABLE 4.21: Typical Three-Phase Pad-Mounted Transformer Capacities—Short-Term Overload Capabilities (in kVA).*


• Estimating peak demand duration (unless itcan be obtained from the consumer) anddetermining the loading capability of a trans-former using the loading tables. This stepbecomes very important when the estimatedload falls between two transformer sizes.

• Using an appropriate power factor to corre-late kW load to kVA load in calculations onconsumer’s load profiles.

Every time a transformer is sized correctly,the cooperative’s capital investment has beenminimized.

MAXIMUM TRANSFORMERCASE TEMPERATURESEffect on Public SafetyIn today’s litigious society, some cooperativesmay be less concerned with their pad-mountedtransformers burning up than they are with hav-ing someone burned by touching the case of anoverloaded unit. This concern is legitimate andmust be addressed. However, the possible prob-lem can be a manageable risk once it is put intoproper perspective. Most people know not totouch the hood of a car that has been sitting inthe sun on a hot summer day. A person touching

4

Example A

A customer has requested service for a convenience store that is 24,000square feet. The customer has provided the following load information:

• Lighting: 80 kW• Electric Heat: 60 kW• Air Conditioning: 60 tons• Water Heater: 18 kW• Refrigeration: 160 kW• Fans: 10 kW• Miscellaneous: 20 kW

In reviewing other similar accounts, it has been determined that a300 kVA or 500 kVA transformer may be needed. Therefore, othermethods must be used to help make this choice.

The following load has been determined by means of diversity factors:

Neglect the electric heat load because the summer load is the domi-nant load. The total diversified load is 247.5 kW. Assuming a powerfactor of 0.9, the kVA demand of this store is

From the chart, a convenience store has a peak duration of eight hours.From the transformer loading table, a transformer with a peak of eighthours can be loaded to 113 percent of its nameplate rating in the sum-mer months. Now, 150 kVA× 1.13 = 169.5 kVA. The calculated load,275 kVA, exceeds the loading capability of a 150-kVA transformer, soa 300-kVA transformer for this customer should be installed, whichagrees with the similar account recommendation.

As another check, the watts/square foot method suggests the follow-ing load:

If a power factor of 0.9 is assumed, the watts/square foot method gives

This approximation may seem a little high for this store compared withthe other methods, but this load would still not exceed the loading ca-pability of a 300-kVA transformer (300 kVA × 1.13 = 339 kVA).

Therefore, after three different methods are considered, the conclusionis to install a 300-kVA transformer to serve this customer.

EXAMPLE 4.8: Sizing Commercial Transformers.

Load Load Diversity ActualDescription (kW) Factor Demand (kW)

Lighting 80.0 0.80 64.0

Electric Heat 60.0 0.75 45.0

Air Conditioning 1.5 0.60 67.5

Water Heater 18.0 0.50 9.0

Refrigeration 160.0 0.60 96.0

Fans 10.0 0.40 4.0

Miscellaneous 20.0 0.35 7.0

TOTAL 378.0 — 247.5

Continued

247.5/0.9 = 275.0 kVA

24,000 sq ft × 12.7 watts/sq ft = 304.8 kW

304.8 kW/0.9 = 338.7 kVA

158 – Sect ion 4

a hot transformer case will likewise naturallyjerk away from it on contact.

Estimating Case TemperatureIt is almost impossible to predict the case tem-perature of a pad-mounted transformer underload because many factors contribute directlyand indirectly to the surface temperature:

• Preloading,• Present load,

• Solar effect,• Wind direction and velocity,• Location of the unit near structures

or shrubbery,• Ambient temperature variation, and• Part of case involved.

To better understand the problem, a majormanufacturer took three of its single-phase, low-profile units to the test floor and measured casetemperatures at full load and at a sustained

4EXAMPLE 4.8: Sizing Commercial Transformers. (cont.)

Example B

A customer has requested service for an office building that has 355,750square feet. The customer has provided the following load information:

• Lighting: 500 kW• Electric Heat: 100 kW• Air Conditioning: 1,250 tons• Cooking: 288 kW• Receptacles: 1,480 kW• Computer Equipment: 600 kW• Motor Load (larger than 40 Hp): 840 Hp total• Motor Load (smaller than 40 Hp): 99 Hp total

A similar account could not be found for this office building. Therefore,other methods must be used to help size the transformer.

The following load has been determined by means of diversity factors:

Neglect the electric heat load, because the summer load is the domi-nant load. The total load is 2,311.7 kW. Assuming a power factor of0.9, the kVA demand of this office building is

Let’s look at another method before making a final decision.

The watts/square foot method suggests the following load:

If a power factor of 0.9 is assumed, the watts/square foot method gives

This approximation is very close to the diversity approximation. Now,the decision must be made regarding what size transformer is to beinstalled.

The peak duration for this office building can be estimated to be eighthours, unless otherwise stated by the customer. On the basis of aneight-hour peak duration, the transformer can be loaded to 113 per-cent of its kVA rating. For a 2,500-kVA transformer, it can be loaded to2,825 kVA during peak times.

Therefore, a 2,500-kVA transformer should be installed to serve thiscustomer.

Load Load Diversity ActualDescription (kW) Factor Demand (kW)

Lighting 500.0 0.80 400.0

Electric Heat 100.0 0.75 75.0

Air Conditioning 1,250.0 0.75 937.5

Cooking 288.0 0.40 115.2

Receptacles 1,480.0 0.15 222.0

Computer 600.0 0.75 450.0Equipment

Motor Load (larger 0.746 840.00 157.0than 40 Hp)

Motor Load (smaller 0.746 99.00 30.0than 40 Hp)

TOTAL 4,818.5 — 2,311.7

2,311.7 kW/0.9 = 2,568.6 kVA

355,750 sq ft × 7 watts/sq ft = 2,490 kW

2,490 kW/0.9 = 2,767 kVA


temperatures and their locations for the threepad-mounted transformers of different sizes.

As a point of reference when viewing thetable, consider that the manufacturer designs sin-gle-phase units of 100 kVA and less to carry ap-proximately 180 percent load for six hours withnormal life expectancy. The three designs listedare based on the industry standard of a 65°C riseor less for 100 percent load. An additional cali-bration point is that the units are designed not toexceed 125°C top oil temperature with a 25°C am-bient temperature at the higher continuous loads.

Tank Temperature Burn ProbabilityThe specter of possible harm from hot pad-mount-ed transformer surfaces was first raised in thetechnical press in 1972 (Tarplay). There was aflurry of activity focused on the problem. How-ever, the best qualitative thermal data on thesubject were developed by E. I. duPont deNemours and Company, Inc., over many yearsthrough research associated with its protectiveclothing activities. From curves developed byduPont and the NASA space program, Table 4.23was developed (Lee, 1973; NASA, 1964).

Table 4.23 shows that the probability of a per-son’s receiving a first- or second-degree burnunder normal loading conditions is very small.Another point to consider is that the contact timeto produce a second-degree burn is about 2.5

4

Rise Above Ambient Temperature, °C (36°C Ambient)

Measurement 25 kVA 37.5 kVA 50 kVALocations 100% Load 180% Load 100% Load 180% Load 100% Load 150% Load

1 9.5 27.0 12.5 34.0 16.5 34.0

2 13.0 44.5 24.0 60.5 31.0 61.0

3 16.5 44.0 24.5 60.5 33.5 55.5

4 16.0 43.0 21.5 50.5 28.0 54.0

5 17.5 — 13.0 37.5 33.5 38.5

6 5.0 14.0 5.5 16.5 8.5 16.0

7 25.5 67.5 35.5 87.0 43.5 84.0

8 26.5 68.0 35.5 87.0 46.5 84.0

Source: ABB Power T&D Company, Inc., Underground Distribution Transformer Division.

TABLE 4.22: Surface Temperatures Measured at Various Locations on the Cases ofPad-Mounted Transformers.

FIGURE 4.14: Case Temperature Measurement Location—Pad-MountedDistribution Transformer.

Front View

Top View

Inside Cabinet

Top of Cabinet

1

3

5

2 4

1 6

7

82 4

6

Top Oil

Inside Oil

overload. As expected, the temperature variedwidely from one part of the case to another.

Figure 4.14 shows the top and front views ofa pad-mounted transformer. The circled numbersone through eight denote the locations of varioustemperature measurements. Table 4.22 lists the

160 – Sect ion 4

times that of the pain level.Under these conditions, a per-son’s normal reflex should op-erate in plenty of time to pullaway from the hot surface be-fore being burned. Althoughthe skin may become red-dened, it generally will notblister. The body’s natural protection system willnormally protect against burns up to about149°C (300°F). A temperature of 149°C seemsquite high not to produce a burn in all instances.The problem is perception. Unfortunately, most

4Ambient Case Time in Seconds

Temperature (°C) Temperature (°C) Pain Blister

36 69 33.0 70.0

36 88 7.5 19.0

36 95 6.0 13.0

36 110 3.0 8.0

36 115 2.5 6.5

TABLE 4.23: Surface Contact Time to Produce Burning.people’s ideas about burns have been formed bytheir personal experience with boiling water,which maintains skin contact and, thereby,causes more severe burns.

DEDICATED TRANSFORMER LOADSMany cooperatives that serve farming communitieswith large irrigation loads and oil fields withproducing wells have applications in which atransformer is dedicated to supply power to onemotor that is the total load on the transformer.

Selecting the proper sizethree-phase transformer forthis type of application is astraightforward process de-scribed by Example 4.9, ex-cerpted from the ABB Distrib-ution Transformer Guide.

In Example 4.9, the motorselected had a starting current

within the range of typical NEMA Code G mo-tors. If voltage drop is a problem, 100-Hp mo-tors with smaller starting currents can be pur-chased, provided that the starting torque charac-teristics are satisfactory for the load being driven.

Transformer cases

get hot but don’t

cause burns.

Continued

Determine the minimum kVA size three-phase trans-former to power a 100-Hp, three-phase, 124-amperefull-load current, 460-volt squirrel cage induction motorwith a locked-rotor current of 725 amperes. The motorwill be driving a center pivot irrigation system. Serviceto the site will be through an underground three-phasecable at 12.47 kV with a minimum length of 1,600 feet.

STEP 1: Determine the locked-rotor kVA of the motor.

NEMA standards specify starting code letters for squir-rel cage induction motors that correspond to the kVAper horsepower required to start the motor. The seriesof curves of Figure 4.15 graphically show the relation-ship between the motor size, the locked-rotor require-ments of the motor, and the transformer thermalcapability. Table 4.24 is based on the locked-rotor codeletters, but it can be used for any motor by selectingthe curve that corresponds to the locked-rotor kVA/Hpof the motor for which the transformer is being sized.

EXAMPLE 4.9: Dedicated Transformer Load.

TRNLJ

GECA

VSPMKHFDB

1 2 3 4 5 7 10 20 30 40 50 70 100 200 300 400 500 700 1,0001

2

3

45

7

10

20

30

4050

70

100

TransformerkVAperM

otorHp

Starts per Hour

FIGURE 4.15: Relationship Among NEMA Starting Code Letters,Starts per Hour, and Transformer kVA per Motor Hp forTransformer Thermal Considerations


4

If the starting kVA or starting code letter is unknown, the locked-rotorkVA of the motor may be calculated with Equation 4.9.

Therefore,

STEP 2: Determine the number of starts per hour planned for the motorunder normal operating conditions.

The load is a water pump driving a center pivot irrigation system. Thesesystems are usually run for weeks at a time after they are started. As-sume one motor start per hour.

STEP 3: From Table 4.24, select the curve letter that corresponds tothe locked-rotor kVA/Hp of the motor.

Therefore,

STEP 4: Enter Figure 4.15 on the X-axis at the correct starts per hourfor the motor being applied. Move up to the intersection of the startsper hour and the correct locked-rotor code letter curve and read thekVA of the transformer required per horsepower of motor from theY axis.

Because motor starts per hour equals one, intersection of curve G withthe Y axis equals 1.5 kVA/Hp.

STEP 5:Multiply the kVA/Hp by the rated horsepower of the motor tofind the smallest transformer to be used in the application. Sizing thetransformer with this procedure is conservative because it assumesthat the voltage maintained at the motor terminals during starting is therated voltage of the motor.

Therefore,

STEP 6:Most motors started across the line require approximately 80percent of rated voltage at their terminals under locked-rotor condi-tions to successfully start. After the transformer has been sized so itcan withstand the starting pulse caused by the motor, check the volt-age regulation of the system from the substation transformer throughthe secondary terminals of the distribution transformer to see if therewill be enough voltage to start the motor. RUS Bulletin 160-3 describesthe procedure to make the voltage drop calculation, plus other usefulinformation.

EXAMPLE 4.9: Dedicated Transformer Load. (cont.)

Code Letter Locked-Rotor kVA per Hp

A 0.00–3.15

B 3.15–3.55

C 3.55–4.00

D 4.00–4.50

E 4.50–5.00

F 5.00–5.60

G 5.60–6.30

H 6.30–7.10

J 7.10–8.00

K 8.00–9.00

L 9.00–10.00

M 10.00–11.20

N 11.20–12.50

P 12.50–14.00

R 14.00–16.00

S 16.00–18.00

T 18.00–20.00

U 20.00–22.40

V 22.40 and up

TABLE 4.24: NEMA Starting Code Letters.

Equation 4.9

where: VR = Rated phase-to-phase voltage of motorIS = Motor starting current at rated voltage

Locked-Rotor kVA =3 × VR × IS

1,000

Locked-Rotor kVA = = 578 kVA(1.732)(460)(725)

1,000

578 kVA/100 Hp = 5.78 kVA/Hp = Letter G

1.5 kVA/Hp × 100 Hp = 150 kVA

162 – Sect ion 4

Also consider the transformer impedance: thelower the absolute impedance (ohms), the lessregulation across the transformer, particularlyduring the motor starting sequence when reac-tive current predominates. Lower absolute im-pedance of the transformer can be accomplishedin two ways: (1) a transformer of the selectedcapacity and the lowest available percentage im-pedance (%Z) can be installed, or (2) the trans-former capacity (kVA) can be increased. Whilethe latter choice may be the more expensive ofthese two options, it will always be less expen-sive than lowering impedance of the primarysystem.

In this example, the primary objective was toensure that the transformer kVA size was ade-quate to start the motor. Mention was made ofthe number of times per hour the motor wouldbe started, but this was not really considered be-cause it was assumed the motor would bestarted only infrequently. The “Starts per Hour”axis in Figure 4.15 is concerned mainly withlimiting the thermal stress imposed on the trans-former by the motor during frequent starts.

Another important consideration in multistartapplications is the effect of the magnitude andduration of the starting current pulse on thetransformer. Each time a motor starts, it essen-tially puts a controlled secondary fault on thetransformer. The transformer must be sized to

4Equation 4.10

where: n = Number of starts per hourIP = Pulse current per unit of transformer

rated current

n =4.25Ip

4

Transformer rated current =180 amperes at 480 volts

Motor starting current = 725 amperesIP = 725/180 = 4.0 pu of transformer rated current

FIGURE 4.16: Maximum Motor Starts per Hour for Transformer Mechanical Considerations.

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Number of Current Pulses per Hour

2 3 4 5 6 7 8 9 10

109

87

6

5

4

3

Maximum

AllowableperUnitPulse

0.1 to 10 Starts/Hour

10 to 1,000

2

1

withstand the mechanical and thermal stressesimposed by this duty. Extensive data have beengathered by manufacturers and utilities aboutpulse duty on transformers. The conclusion isthat, if the current pulses per hour exceed thoseshown in Equation 4.10, the transformer will failprematurely because of the repeated mechanicalstresses placed on the core and coils.

Figure 4.16 shows the curve for Equation 4.10.Look back at the previous pad-mounted trans-

former sizing example (Example 4.9) to deter-mine the number of starts per hour limitation toensure normal life expectancy of the 150-kVAtransformer selected:


By entering the curve on the X-axis at 4 pu,one can see that the allowable number of startsshould be limited to less than 1.25 per hour.

It should also be noted that there are somemotor applications that impose significant ther-mal and mechanical stresses on transformerswithout multiple starts per hour. This is particu-larly true for motors serving loads that may

cause the motor to approach stall conditions.Examples include rock crushers and feed mills.In these cases, the same basic calculationsshould be run for the particular motor using thecurrent drawn by the motor near the torque-breakdown curve. The results should then beevaluated considering the frequency of the ex-pected stall conditions.

4


1. Ampacity is defined as the ability of a cableto carry maximum current under a specificset of conditions.

2. Cable ampacity can be calculated, but, in mostinstances, single-phase and three-phase cableampacities are selected from ampacity tables.

3. The maximum ampacity of UD cable is setby the operating temperature of its insula-tion and depends on the ability of its sur-rounding environment to dissipate the heatgenerated in the conductor, concentric neu-tral, and insulation.

4. The maximum temperature rise of a cabledepends on the shape of the load durationcurve, which depends on the relationshipbetween the loss factor and load factor ofthe circuit. Current values listed in ampacitytables are always calculated using a corre-sponding load factor.

5. Cable ampacity is affected by the ability ofsurrounding soil to dissipate heat generatedwithin the cable. This fundamental propertyis called soil thermal resistivity.

6. Soil thermal resistivity depends on the typeof soil, its moisture content, and the struc-tural arrangement of the soil particles.

7. Soil thermal resistivity depends mainly onmoisture content that is seasonally variable.

8. Ambient soil temperature affects ampacitybecause the insulation temperature rise isadded directly to it to determine the maxi-mum cable conductor temperature.

9. The ampacity of three-phase installations isreduced as a result of mutual heating betweenthe phases and losses in grounded concentricneutrals resulting from circulating currents.

10. Losses in grounded concentric neutrals ofthree-phase applications are affected by thephysical arrangement of the individual phases.

11. Cables placed in conduit have less ampacitythan do direct-buried installations.

12. Direct-buried cables should be de-ratedwhen they are installed in vertical riser poleapplications.

13. Risers should be open at the top and ventedat the base to maximize ampacity and tocounteract solar heating effects.

14. For three-phase circuits buried in conduit, theriser usually is not the element that limits load.

15. Ambient air temperature is the most impor-tant element in determining how much loada pad-mounted transformer can carry overits expected lifetime (30 years minimum).

16. Transformer daily peak loads should beselected from loading guides after predict-ing what the temperature will be duringthe peaks.

17. Two methods should be used together topredict temperature for the month involved:

(a) Average of all daily highs and all dailylows for several years, and

(b) Average of the high and low of thehottest day over many years.

18. Transformer thermal time constant andthermal aging characteristics of its insula-tion allow short-time peak overloads tobe carried without decreasing normal lifeexpectancy.

19. Equivalent initial load and equivalentpeak load must be calculated to performloading studies.

20. Preload conditions should be consideredwhen loading transformers. Preload levelsgiven in loading guides are based on trans-former nameplate rating and are not a per-centage of peak load.

164 – Sect ion 4

21. For cold weather conditions, a maximum load-ing above 1.8 per unit cannot be justified forpreload conditions above 50 percent of peakload. This means many per-unit figures above2.0 per unit given in ANSI/IEEE C57.91-1981tables do not apply in practical situations.

22. Load-estimating guides based on load diversityand demand should be used to estimate peakkVA transformer load for groups of residentialconsumers. A loading guide developed specif-ically for the geographical region surroundinga cooperative’s service area should be used.

23. The surface temperatures of pad-mountedtransformer cases can exceed 60°C duringpeak loading on sunny days. However,tests have shown that a person’s normalreflex action in response to touching a hotsurface should prevent burning under nor-mal conditions.

24. Pad-mounted transformers for dedicatedmotor loads should be properly sized basedon motor locked-rotor kVA and the numberof starts per hour.

4

Grounding and Surge Protect ion – 165

Grounding andSurge Protection5

In This Section:

When cooperatives first started installing primaryunderground distribution systems, they usedBCN cable, which, at that time, was an industrystandard and a very effective way to providegood system grounding. Unfortunately, these ca-bles failed long before the end of their expectedlife because of electrochemical treeing in the in-sulation layer that was accelerated by moistureand high-voltage stress. In addition, because ofsimilar electrochemical action, the corrosion anddisappearance of the bare concentric neutralswas also a major problem.

A solution to these problems was the additionof an outer jacket over the concentric neutral ofthe cable. This jacket can take the form of an in-sulating jacket or a semiconducting jacket. RUScable specifications were changed in 1987 to re-quire an electrically insulating jacket to be ap-plied over the cable. The jacket provides physicalprotection for the cable and helps prevent moisturecontact with the insulation layer. The jacket also in-sulates the concentric neutral from direct contactwith soil. Unfortunately, this feature reduces theperformance of the cable grounding system.

The function of the cable grounding system isto keep the cable as close to earth potential(“grounded”) as practicable at all times—duringboth normal and abnormal operating and underfault conditions. Proper grounding minimizesthe effects of lightning surges on undergroundcomponents after the surges are discharged bylightning arresters. Several factors affect the per-formance of the grounding system. Low riserpole ground resistance and the application ofcounterpoise wires reduce jacket voltages. Thereare also various methods to measure and calcu-late system ground resistance.

Protection of the underground distributionsystem from lightning surges that originate onoverhead lines is crucial. The application of riserpole arresters and lead length must be consid-ered. Traveling waves on underground systemsaffect protection methods and dead-front ar-rester locations of different cable configurations.Through careful arrester location, higher protec-tive margins than suggested by standards can beachieved. Refer to IEEE for assistance in apply-ing distribution arresters.

Cable Grounding System Function

Factors Affecting Cable GroundingSystem Performance

Counterpoise Application for InsulatedJacketed Cable

System Ground Resistance Measurementand Calculation

Underground System Surge Protection


166 – Sect ion 5

Before the function of the cable grounding sys-tem can be explained in detail, the term groundneeds to be defined as used in this section. Aground is a current-carrying connection thatconnects a piece of equipment or a circuit toearth. The purpose of the connection is to main-tain a point in the circuit or on the equipment asclose to earth potential as possible. A ground ismade up of a ground conductor, a bonding con-nector, its ground electrode(s), and the soil sur-rounding the electrode. The most common typesof ground electrodes are:

• Driven ground rods,• Buried counterpoise wires,• Cables with bare concentric neutrals,• Concentric neutral cables with semiconduct-

ing jackets,• Metallic water or sewer systems, and• Rebar in reinforced concrete in manholes

and vaults.

Note that a pole butt ground applied to pro-tect a distribution pole from lightning damage isnot considered an effective ground electrode.

For discussion purposes, the cable groundingsystem consists of the grounding circuit and theneutral circuit. The difference between the twocircuits is that the neutral circuit is expected tocarry current under normal operation, and thegrounding circuit isn’t. The grounding circuit ismade up of ground electrodes, ground conduc-tors, and all connections. The neutral circuit in-cludes the cable concentric neutral and anyconnections to it, and may include a separateneutral conductor.

Under ideal circumstances, the grounding sys-tem maintains all points connected to it at earthpotential during all normal and abnormal oper-ating and fault conditions. For this ideal goal tobe met, all connections between it and the earthmust have a resistance of zero ohms; in reality, azero resistance ground cannot be obtained. Byusing low-resistance conductors and electrodes,the design engineer can minimize the resistanceof the metal circuit up to and in the earth. Howev-er, the engineer has no control over the resistivityof the soil in direct contact with the electrode,which is usually the most significant aspect in

5determining the actual ground electrode resis-tance. According to Ohm’s Law (V = I×R, voltageequals current times resistance), if the ground re-sistance is relatively high at the point of a light-ning current surge or a system fault, extremelyhigh voltages can result. A low ground resistancewill discharge lightning strokes with a lowerprobability of system disturbance. A good groundwill improve the chances for rapid operation ofprotective relays and fuses to clear faults andlimit personal injury and equipment damage. Agood ground will also lower the voltage existingbetween grounded objects, such as transformercases, and the nearby earth surface during faultconditions.

The magnitude of the ground resistance canbe found by measuring the resistance of the sur-rounding soil to the flow of current. This resis-tance is usually associated with driven groundrods and, in theory, can be calculated withEquation 5.1.

Cable GroundingSystem Function

Equation 5.1

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Length of the current path, in metersA = Area of current path, in square

meters

R = ρ LA

The easiest and best method to find the valueof ground resistance is to measure it with aground resistance tester. The reading is obtaineddirectly in ohms. Soil resistivity is most accu-rately measured with a four-point earth resis-tance tester. Soil resistivity can vary widely overa small geographical area and is affected by thetype of soil, moisture content of the soil, andsoil ambient temperature. More information onfield measurement of ground resistance, soil re-sistivity measurements, and the various elementsthat affect soil resistivity may be found in a latersubsection, System Ground Resistance Measure-ment and Calculation.


PUBLIC SAFETYA well-designed, -constructed,and -maintained groundingsystem is essential to the oper-ation of any electrical distribu-tion system to maintain allcommon points connected toit as close to ground potentialas practicable. Proper grounding of a four-wire,wye-connected, effectively grounded systemprovides the following functions:

• Limits voltage across line-to-ground insulation,

• Provides a path to shuntsurge currents from thesystem,

• Allows ground faults to beisolated quickly,

• Reduces the shock hazardto people by reducing touch voltages duringfaults on electrical equipment cases andframes to safe levels, and

• Improves the likelihood that ground faultswill be isolated quickly.

Unlike an overhead system in which equip-ment is physically raised above public areas,most UD systems have equipment enclosuresmounted on the ground within easy public ac-cess. If a phase conductor contacts an enclosure,no dangerous voltages should exist because theenclosure could be touched by a member of thegeneral public or the cooperative’s crews. Todecrease the chances of a shock, ensure that theenclosure is connected to the lowest possibleground resistance. Another way to reduce touchvoltage on pad-mounted equipment is to installa buried counterpoise system around the system.

One way someone could accidentally comeinto contact with an energized conductor is bydigging into a cable. All RUS-accepted UD pri-mary cable is manufactured with concentric neu-tral wires that provide some electrical protectionfor someone digging into it. The theory is thatthe metal digging tool would first contact thegrounded neutral wires and then the conductor,thereby creating a low-impedance path betweenthe conductor and the concentric neutral wires.

5This low-impedance pathshunts most of the fault cur-rent through the groundedsystem neutral.

Over the years that UD sys-tems have been in place, theyhave established an excellentsafety record. One reason is

that a good grounding system exists, resulting, inpart, from the use of bare concentric neutralcable that provides a large neutral surface in di-

rect contact with the soil.However, because of corro-sion, changes in the watertable, changes in facilities, andthe increasing use of JCNcable, more careful attentionshould be paid to the installa-tion of the grounding system.

RETURN CURRENT PATHThe typical underground distribution system is athree-phase, four-wire wye with multigroundedneutral, which satisfies the definition of an effec-tively grounded system. The neutral circuit mustbe a continuous metallic path along the route ofthe primary feeder and must extend to everyconsumer’s location. For this requirement to bemet, the concentric neutral of jacketed cablemust be grounded at each distribution trans-former, at frequent intervals (specified below)where no transformers are located, and at drivenground rods at each user’s service entrance. Be-cause the concentric neutral is multigrounded, itis connected in parallel with the earth, whichforms a relatively low resistance path to the flowof current. Under normal operating conditions,residual current caused by unbalanced phase-to-neutral loads on primary circuits returns to theneutral of the substation transformer along thisparallel path. In no instance, even under emer-gency conditions, should the earth ever be usedas the only path for the return of normal loadcurrent on a distribution system.

For typical overhead rural distribution lines, ithas often been assumed that 40 percent of thereturn current is carried by the neutral with 60percent returning through the earth. However,the current division will vary depending on earth

Proper grounding

increases

personal safety.

Pay attention to

how JCN installations

are grounded.

168 – Sect ion 5

resistivity and the size of the neutral, especiallyin the case of JCN underground systems wherethe neutral is grounded only by ground rods orby counterpoise wires. If the neutral is the samesize as the phase conductor, which is usually thecase for single-phase underground circuits, thecurrent in it will be almost as large as the phasecurrent. As the size of the concentric neutral isreduced, the greater the current flow in theearth. However, this change in current distribu-tion does not have a linear relationship to theratio change in the neutral size. On single-phaseprimary circuits, RUS specifies that the concen-tric neutral and phase conductor must have thesame conductivity.

In a perfectly balanced three-phase system,no neutral or ground currents flow. However, asstated previously, unequal phase-to-neutralloads will cause an unbalanced current to flowin the return path. Normal practice is to try tokeep loads balanced for the system to operateefficiently. For this reason, the concentric neutralsize in a three-phase circuit can be much smallerthan the phase conductor. Cooperatives may op-erate three-phase systems with three cablesspecified at 1/3 neutral each, or 100 percent ofthe conductivity of a single-phase conductor.Most engineers recognize that a 1/6 neutral,with a combined three-phaseconductivity of 50 percent ofthe conductivity of one phaseconductor, is enough for mostoperating systems. Reducingthe size of the neutral has theadditional benefit of reducingthe circulating currents in-duced in the concentric neu-trals when they are groundedand connected to each other, which increasescable ampacity and reduces losses.

The grounding and neutral circuits also pro-vide a way to ground the neutral of both three-phase and single-phase pad-mounted distribu-tion transformers. The transformer neutral isconnected to the cable concentric neutral andboth are tied to at least one ground rod. Thetank should be grounded at two points by sepa-rate connections to ensure that it cannot becomeungrounded through accident or corrosion.

For secondary single-phase, three-wire,120/240-volt systems, the two energized con-ductors plus the grounded neutral from thetransformer are run to the user’s service en-trance where the neutral is again connected to adriven ground rod. The user’s ground circuit isdirectly connected to the grounded neutral ofthe transformer to ensure that no potential dif-ferences can exist between the two systems. Ef-fective grounding is especially important toprotect 120-volt equipment connected acrosstwo halves of the 240-volt transformer sec-ondary. The solid neutral connection holds theneutral at a point halfway between the 240-voltconductors. If the user’s neutral becomes iso-lated from the transformer neutral point, unbal-anced voltages across the equipment will result.The voltages across the two 120-volt legs willsplit in proportion to the impedance of the loadon each side of the circuit, possibly causingburned-out light bulbs or damaged appliances.

NEUTRAL CIRCUIT FUNCTIONUNDER FAULT CONDITIONSOn distribution circuits, the principal means offault protection are the overcurrent relay andfuse. For these types of devices to sense a short-circuit condition and act quickly to interrupt the

fault, the fault current magni-tude must be considerablyhigher than the maximum loadcurrent. The most probabletype of fault on an under-ground circuit is the single-line-to-ground (SLG) fault.Simply stated, the amount offault current depends on thefollowing:

• The impedance of the source,• The voltage at the source,• The line impedance from the source to the

point of fault,• The impedance to ground at the point of

fault, and• The impedance of the fault.

Fortunately, in UD systems, unlike overhead,the cable concentric neutral is usually involved

5

Reducing neutral

losses increases

three-phase circuit

ampacity.

in an SLG fault, which allowsthe maximum available faultcurrent to flow. A large faultcurrent ensures that protectivedevices act quickly and posi-tively to protect equipmentfrom excessive damage andreduce the possibility that any-one will be harmed.

Another function of the neutral circuit is toprovide a low-resistance ground at a pad-mounted transformer or other equipment loca-tion. A low resistance is needed to reduce thechance of a dangerous touch potential for anSLG fault in the transformer. The multigroundedneutral in parallel with ground rod(s) at the lo-cation will provide the necessary protectionunder all except the most unusual conditions.

JCN cable, with an insulated jacket, must begrounded at least four times per mile for delib-erate-separation areas, and at least eight timesper mile for random-separation areas. (See the2007 NESC, Rules 96C and 354D3c.) Cables withbare concentric neutrals or with a semiconduct-ing jacket (meeting NESC Rule 94B5) may em-ploy the concentric neutral as a made electrodeand the grounding requirements for the cableare met, provided the installation complies with2007 NESC Rule 354D2. If the required numberof grounds to the JCN (insulated jacket) is notobtained at sufficient transformer locations, thecable neutral must be connected to groundrod(s) at intermediate points. In three-phaseruns, the neutrals of all three cables must beconnected together with No. 4 or No. 2 AWGcopper grounding conductor and tied to earth

with driven rod(s). It is recom-mended that No. 4 AWG cop-per ground wire be used tobond no larger than 400-kcmilcables with 1/3 neutral. No. 2AWG will be sufficient to bondto 1/3 neutral 500- to 1,000-kcmil cable.

The neutrals of three-phasecircuits should be connected together and ground-ed to keep them at or near ground potential. Un-der fault conditions, interconnected neutrals andgrounding will reduce the probability of arcingbetween the concentric neutral of a faulted cableand other nearby neutrals, or other groundedmetallic paths. This procedure also reduces thedanger to personnel who may be working in amanhole or enclosure when a cable fault occursby keeping metallic objects at the same potential.

The secondary low-voltage neutral circuit isgrounded at the pad-mounted transformer second-ary and at the service entrance of a consumer. Atthe point of delivery (the meter), another metallicground is required from the breaker panel to ametallic water pipe or a suitable made electrode.The grounds are necessary to prevent excessivevoltages from developing between plumbing fix-tures and appliances connected to the householdwiring system. Another contingency corrected inpart by the neutral grounding scheme is the pos-sibility of a fault between the high- and low-volt-age windings of the transformer. In this scenario,primary voltage could be impressed on the fit-tings of 120/240-volt appliances, causing a fire. Ifthe secondary winding is grounded at the trans-former, a high-voltage insulation failure involv-

ing the secondary winding will immedi-ately be shorted to ground by the centertap of the winding or by the core, blow-ing the primary fuse and isolating the cir-cuit from the source. The transformerground thus prevents dangerous primaryvoltage from existing on the secondaryconductors. See Figure 5.1.

SURGE PROTECTION GROUNDINGInterest in the transient response or surgeimpedance of tower footings and drivenground rods began in the early 1930s


5A low-impedance

neutral path allows

fast protective

device operation.

FIGURE 5.1: Typical Distribution Transformer Core Form Design and NeutralGrounding Circuit.

LV = Low VoltageHV = High Voltage

Core

Core

LVFault

HV

LVHVLV

TransformerGround Service

Ground

SecondaryNeutral

HouseGround

Wingdings

170 – Sect ion 5

when engineers were trying to improve the out-age rates of transmission lines. The main cause ofoutages was found to be direct lightning strokesto phase conductors. The protection method de-vised at the time required new line designs basedon shielding the conductors from direct strokesthrough a combination of shield wires connectedto ground conductors plus adequate phase-to-ground insulation. When lightning strikes theshield wire, the surge current is diverted toground. It was found that a low surge imped-ance at the base of the structure is required tomake the scheme work. Otherwise, a large surgecurrent will produce a voltage at the top of thetower greater than the basic impulse insulationlevel (BIL) of the insulator string, causing abackflash to the conductor (Westinghouse T&DReference Book, 1964). This same principle ap-plies to the dissipation of surge currents in un-derground systems. Therefore, it is important toknow the value of protection obtained fromgrounds when they are required to carry light-ning discharge currents.

It is, thus, necessary to establish the relation-ship between what will be called the surgeimpedance (ZSURGE) of a ground rod and itsmeasured 60-Hz resistance (R60-Hz) and deter-mine how this difference does or does not affectlightning arrester protection. It is also necessaryto understand the effect of lightning dischargepath surge impedance on the protection and op-eration of underground systems using JCN cable.

Difference Between 60-HzGrounding and SurgeGroundingGround rods are the mostcommon type of electrodeused on utility distribution sys-tems. The magnitude of theirsurge impedance (ZSURGE) andthe elements that affect it areof major concern. Counter-poise wires are also used to lower ground resis-tance. Because their initial effect on groundingdepends on the surge impedance of a buriedwire, they are covered in the subsection,Counterpoise Application for InsulatedJacketed Cable, later in this section.

Previous field and laboratory tests haveshown that the surge impedance of a groundrod or a group of driven rods is defined as theratio of peak voltage to peak current, and thatZSURGE, in ohms, is less than the 60-Hz measuredvalues. Results also show that the surge imped-ance decreases considerably with increasing cur-rent. The actual magnitude of ZSURGE dependson many different elements (Bellaschi, Arming-ton, and Snowden, 1942):

• Soil resistivity,• Soil critical breakdown gradient,• Surge current magnitude,• Surge current waveshape (rate of rise), and• Ground rod length, number, and configuration.

Ground rod resistance is usually expressed asthe measured 60-Hz value; however, transmis-sion and distribution line lightning performancedepends on the impulse or surge value of theground rod impedance. In jacketed cable instal-lations, the cable jacket “sees” a voltage which isthe sum of the IZSURGE (current × surge imped-ance) of the ground electrode plus the down-lead component that is due to the surge currentflowing into ground at the riser pole. The mag-nitude of the surge impedance at the base of thepole also determines how much surge current isdiverted to the JCN and flows to remote con-nected grounds.

In soils of low or medium resistivity, drivenground rods can usually obtain adequate

grounding. For these grounds,the surge impedance is lessthan the 60-Hz (R60-Hz) resis-tance value. The decrease canbe shown by plotting ZSURGE

against the peak current asshown in Figure 5.2, whichdepicts the ZSURGE of variousgrounds for peak surge cur-rents ranging up to 12 kA. In-

specting the curves shows that, for clay soilswith relatively low resistivity, ZSURGE will be lessthan R60-Hz, but not to the extent exhibited bysandy soils with much higher resistivity. For in-stance, the top curve represents an eight-footrod driven into ordinary sand with a measured

5

ZSURGE decreases

with increasing

lightning current

magnitude.


60-Hz resistance of 120 ohms. At peak surgecurrents above 6 kA, it can be seen that ZSURGE

is less than 40 ohms, a 67 percent decrease. Forgrounding resistances of 10 ohms or less, thesurge impedance is not appreciably smallerthan the 60-Hz resistance value.

Different kinds of soil and types of ground canalso be compared by looking at the surge char-acteristic of grounds shown in Figure 5.3. Here,the ratio of surge impedance to 60-Hz resistance(ZSURGE/R60-Hz) is plotted against peak surge cur-rent. In this figure, curve 2 represents a 10-footgalvanized steel rod one inch in diameter driveninto moist clay with a 60-Hz resistance measuredat 27.5 ohms. Curve 1 shows four of the samerods as shown in curve 2, spaced in a square 10feet apart with a measured R60-Hz of 9.7 ohms.As the surge current increases above 12 kA, theZSURGE/R60-Hz ratio of the single rod is less than0.4, while the four rods in parallel will not havea ratio substantially below 0.7 at higher currents.

To summarize,

• The surge impedance (ZSURGE) of a groundrod or ground rod group is defined as theratio of peak voltage to peak current.

5

FIGURE 5.2: Variation of Surge Impedance with Surge Current forVarious Values of 60-Cycle Resistance. Source: Westinghouse T&DReference Book, 1964, page 593.

FIGURE 5.3: Surge Characteristics of Various Ground Rods. Source: Bellaschi, Armington, andSnowden, 1942, page 353.

60-Cycle Resistance

Rods In Sand

Rods In Clay

2,000 4,000 6,000

Peak Surge Current (Amperes)

Peak Surge Current (Kiloamperes)

Z SURGE(Ohms)

8,000 10,000 12,0000

20

40

60

80

100

120

Four 10-ft Rods in Parallel, in Clay

10-ft Rod in Clay

1.

0 2 4 6 8 10 12 14 16 180

0.2

0.4

0.6

0.8

1.0

2.

8-ft Rod in Sand

8-ft Rod in Gravel & Stones with Clay Mixture

8-ft Rod in Stones with Clay

RatioofZ SURGEtoR 6

0-Hz

172 – Sect ion 5

• ZSURGE is always less than or equal to themeasured 60-Hz resistance of the ground rod(s).

• ZSURGE decreases with increasing surge currentmagnitude.

• The proportional reduction of ZSURGE is lessfor grounds of low resistance than it is forgrounds of high resistance.

Arrester Discharge PathsSurge arresters are applied on distribution linesfor two main reasons:

1. To shunt lightning currentsurges to ground, whichreduces the magnitude ofsurge voltages propagatingon overhead and under-ground systems, and

2. To limit overvoltages onprotected equipment.

For the first application to be effective, theremust be a low surge impedance to ground. Inthe second application, ground resistance is nota consideration because the voltage acrossequipment is limited to the arrester dischargevoltage plus the voltage drop produced by thearrester lead(s). However, other elements mustbe considered when arresters are applied to pro-tect JCN cable.

At the riser pole on wye-connected distribu-tion systems, the arrester down lead is con-nected to the pole ground conductor, themultigrounded system neutral, and the concen-tric neutral of the jacketed cable. Because pri-mary and secondary neutrals are tied together atthe pad-mounted transformer, the JCN providesa direct path for discharge currents to flow tothe neutrals of premises that the transformerserves. The amount of surge current that flowson the various neutrals is determined mainly bythe surge resistance of the pole ground. Surgevoltages induced by discharge currents can dam-age the cable jacket and consumer appliances.Various arrester discharge paths that occur at ariser pole have an effect on cable insulation pro-tective margin, cable jacket neutral-to-groundvoltage rise, and how current surges on the sec-ondary neutral can damage consumer equipment.

There are also various ways to reduce the magni-tude of discharge currents on the neutral circuit.

Arrester LeadsLightning is a current generator. Surge arrestersare applied at riser poles to protect cables fromlightning-induced overvoltages by shunting thesurge current to ground. Surge voltages pro-duced by a lightning flash are a function of thecurrent magnitude, its rate of rise, and the dis-charge path impedance. The arrester is con-nected to the overhead conductor and the pole

ground conductor. The dis-charge path that determinesthe voltage impressed acrosscable insulation is the arresterand its connecting leads thatcarry lightning current in paral-lel with the cable termination.

This concept is illustrated inFigure 5.4. Two riser pole installations are shown;the lightning discharge paths are highlighted.Pole 1 represents the desirable connectionwhere no current flows through leads L1 and L2.Cable phase insulation will “see” only the ar-rester discharge voltage. Pole 2 is not desirablebecause the level of protection provided by thearrester is reduced when lead voltages L1 and L2

are added to the arrester discharge voltage.Arrester lead length must be considered in

calculating protective margin when evaluatingcurrent rate of rise. The protective margin is thedifference between the arrester discharge voltagesplus the lead L di/dt drop and cable withstandlevel, where di/dt is the change in current withtime expressed as kA/µs (kiloamperes per micro-second). Protection standards suggest using anaverage rate of rise of 4 kA/µs. Tests have shownthat the conductor normally used for leads hasan inductance, L, of about 0.4 µH/ft. The leadlengths connecting the arrester to the termina-tion will contribute approximately 1.6 kV/ft tothe total voltage across the insulation if they car-ry lightning surge current. The 1.6 kV/ft figure isbased on an average probable rise time. Fieldinvestigations have shown that this figure will beexceeded 30 percent of the time. Some applica-tion engineers believe 6 kV/ft or higher shouldbe used. To minimize the effect of current rate

5

Keep arrester leadsshort to maximize

protection.


of rise, the leads should be kept as short as pos-sible and arresters with low discharge voltagesshould be used. See Figure 5.5.

The effect of lead length on protective mar-gins will be covered in more detail in the SurgeArrester Application Factors subsection later inthis section.

Pole Ground ConductorAfter a surge arrester operates to protect cableinsulation, some engineers assume no additionaldamage will happen to other system compo-nents. This assumption is not always true. Oncelightning current goes through an arrester, itflows into the neutral and ground circuits, caus-ing overvoltages on neutral-to-ground insulation.This is especially a problem with electronicequipment (controllers, RTUs, etc.) that might beon the pole. Special methods should be consid-ered to limit or eliminate problems this conditioncan and will cause.

Figure 5.6 shows a typical underground pri-mary installation fed from a riser pole and pad-mounted transformer. The direct-buried jacketed

5

FIGURE 5.4: Arrester Lead Length for Two Riser Pole Installations.

FIGURE 5.5: Three-Phase InstallationShowing Optimum Riser Pole ArresterLead Connections.

Pole 1 Pole 2

Lead L1

CableTermination

Lead L2

L1 + L2 = 0(Desired)

Lead L1

JCN CableLead L2

L1 + L2 = Lead Length(Should Not Be Used)

• Objective is to make certain no lightning current flowsin the leads connected to the cable termination.

174 – Sect ion 5

cable and below-grade connections are alsoshown. Figure 5.7 shows the same installationexcept drawn in a way to highlight the variousarrester discharge paths:

• Pole ground conductor,• Cable jacketed JCN,• Counterpoise, and• Overhead multigrounded system neutral.

After the lightning current passes through thearrester, it splits among the various paths. Therespective surge impedances of the conductorsand the surge impedance of the pole ground de-termine how the current initially divides. Result-ing currents flow to both the local ground andremote grounds.

Jacket VoltagesLocal ground in this instance is the riser poleground rod. When the pole ground conductssurge current, it produces a ground potentialrise when measured relative to a remote refer-

ence point. The condition could be compared toground potential rise in a substation during aground fault. Because the cable concentric neu-tral is tied to the ground rod, any transient volt-age produced by the surge event is transferreddirectly to it. The cable jacket, applied to protectthe concentric neutral from environmental dam-age, also insulates it from ground, which meansthe total ground potential rise is disseminatedacross the jacket. The magnitude of the peakground potential rise can be estimated as thepeak current times the surge impedance of theriser pole ground rod(s).

Laboratory tests have shown that peak jacketvoltage occurs at a distance where the electricfield strength around the ground rod and theground potential rise approach zero. The con-cept can be better understood by referring toFigure 5.8. The area outside the circle representswhere ground potential rise is zero. The groundrise is maximum at the center of the circle wherethe ground rod is located. A jacketed cable startswith its concentric neutral attached to the rod

5

FIGURE 5.6: Typical Primary and Secondary Underground Installation.

Pole GroundTransformer Ground

Service Ground

To Next TransformerTriplexSecondaryCable

Phase Conductor

Multigrounded System Neutral

Counterpoise

ContinuousCounterpoise

Connections ShownBelow Grade For Clarity

Loop FeedPad-MountedTransformer

JCN Cable


and extends radially from the center. It ends at apoint that is not affected by surge current flow-ing in the center ground rod. Measuring thevoltage rise at points A and B from a remote ref-erence gives maximum voltage at A and zerovolts at B. (The ground rise is measured by dri-

ving a two-foot spike in the ground at eachpoint.) Because the concentric neutral of theJCN cable is tied to the ground rod, the peakground potential rise is transferred on the neu-tral to point B, where maximum voltage-to-ground exists across the jacket. Laboratory tests

5

FIGURE 5.7: Schematic Diagram Showing Surge Current Paths After Lightning Arrester Discharge.

FIGURE 5.8: Maximum Jacket Voltage (Neutral to Ground) Produced by Lightning Current Surgein Ground Rod.

Pad-MountedTransformer

Consumer’sBreakerPanel

Loads

Phase Conductor

Multigrounded System Neutral

MOV Cable Pothead

½½

JacketedConcentricNeutral

Continuous CounterpoiseWire to 1st Transformer

Maximum GroundPotential Riseat Point AV = Max

Jacket Voltageat Point AV = 0

Ground Rod

Outside the CircleRepresents the Area ofMaximum Jacket Voltage

At Point B:Ground Potential RiseJacket Voltage

V = 0V = Max

Cable Start Cable End

ZSURGE

RLR1R2

R3

RS

RN

RS

LL

RPole

RTX RServiceZSURGE

InsulatingJacket

Pole GroundConductor

Groundline

V

A B

176 – Sect ion 5

show that maximum jacket voltage occurs within50 feet of the riser pole. Laboratory tests havealso shown that lower jacket voltages will bemeasured at the end of the cable. Cable start andcable end voltages should not be the same, be-cause the cable neutral potential is produced bythe current in the two grounds and their respec-tive surge resistances (GE Research Project, 1990).

The ground potential rise and the maximumjacket voltage are a function of the down-leadcurrent and the surge impedance of the riser poleground rod. Increasing either of these quantitieswill lead to higher jacket voltages. If the groundrise exceeds jacket withstand strength, a jacketpuncture will occur, allowing moisture to enterthe cable. Over time, this condition could leadto loss of one or more of the neutral conductorsto corrosion.

Unfortunately, no standards exist that definethe withstand strength of 50- and 80-mil jacketsmost commonly used on underground cables.The only voltage test required by standards isthe AC Spark Test that is used mainly as a qual-ity control check during the jacket extrusionprocess. An 80-mil polyethylene jacket mustwithstand 7.0 kV applied be-tween an electrode on the out-side surface of the jacket andthe concentric neutral for notless than 0.15 seconds. Labora-tory tests have shown that newpolyethylene insulating jacketshave a surge (1.5 × 40 µswaveform) withstand strengthof about 2,500 volts/mil at20°C. After being in service,this value drops to about 1,200 volts/mil aftermoisture permeates the jacket. On the basis ofthese figures, Table 5.1 lists withstand strengths

5

Jacket Thickness* New Jacket Insulation Aged Jacket Insulation

50 mil 125 kV 60 kV

80 mil 200 kV 96 kV

95 mil 240 kV 114 kV

* Jacket thickness over neutral wires

TABLE 5.1: Surge Withstand Strengths of Polyethylene InsulatingJackets for 15-kV, 25-kV, and 35-kV Class JCN Cable.

for the most commonly used jacket thicknesses.This analysis shows that the neutral on the

JCN cable will not be at ground potential whena surge occurs. As with an overhead system, theneutral-to-ground voltage can reach dangerouslevels during surges.

Jacketed Concentric NeutralAny lightning current that does not propagatealong the other paths attached to the arresterdown lead will flow on the concentric neutral.The JCN current magnitude depends on thesurge impedances of all connected paths. Slow-front waves and 60-Hz currents do not “see” thesurge impedances of the JCN and the otherpaths. The 60-Hz measured resistances and im-pedances will be seen instead. The 60-Hz im-pedances of each path are lower than their surgeimpedance values. If the paths are connected toground resistances lower than or equal to thepole ground, a small change in the pole groundresistance can mean a large current increase onthe concentric neutral and other paths. The pathwith the lowest ground resistance will receivemost of the current.

Another look at Figure 5.7shows that any increase in ca-ble neutral current is trans-ferred directly to the neutral ofthe pad-mounted transformerbecause of the cable insulatingjacket. Any current dischargedby a dead-front surge arresterapplied on the primary termi-nals of the transformer will alsoadd to the contribution from

the JCN. If the transformer ground is much low-er than the service ground, most of the lightningcurrent on the neutral will flow to earth at thetransformer ground rod. If the reverse is true,most of the current will flow on the service neu-tral and to the ground at the service entrance.Damaging overvoltages can be induced on loadsR1, R2, and R3 connected inside the residenceunder this condition as a result of surge currentcomponents flowing in the service neutral.

The surge impedance that has the greatest ef-fect on current division between discharge pathsand surge voltages on the secondary is the poleground. Keeping this resistance as low as practi-

Minimize jacket

voltage with low

riser pole ground

rod resistance.


cable means minimum lightning energy on theunderground system neutral. The transformerground must be a minimum resistance becausesome service grounds are tied to undergroundmetallic water systems. The most economicalway to obtain good grounds in the above twoinstances is by multiple ground rods, deep-dri-ven rod(s), or the addition of counterpoise.

CounterpoiseA continuous counterpoise conductor is shownconnected to both ends of the jacketed cable inFigures 5.6 and 5.7. It is buried with the cableand represents another arrester discharge path atthe riser pole. Laboratory tests have confirmedthat, applied as shown, counterpoise will reducethe jacket voltage up to 50 percent under surgeconditions. Adding counterpoise also improvesthe 60-Hz grounding of the riser pole arresterand cable neutral. Direct connection to the JCNdecreases surge current transfer to the trans-former neutral. Note that counterpoise is usedonly for JCN applications and is not requiredwhen BCN or semiconducting jacketed cableis installed.

How counterpoise reduces jacket voltage andimproves 60-Hz grounding is explained in moredetail in the subsection, Counterpoise Applicationfor Insulated Jacketed Cable, later in this section.

Overhead Multigrounded System NeutralThe overhead system neutral presents two dis-charge paths for lightning current once it passesthrough the arrester. Surge current will flow in bothdirections away from the riser pole. The surgeimpedance of the two paths is approximately500 ohms each, calculated from Equation 5.2 fora single aerial conductor with ground return.

As can be seen, the surge impedance is deter-mined only by the height of the conductor

5Equation 5.2

where: Z = Surge impedance of conductorL = Inductance of conductor (Henries)C = Capacitance of conductor (Farads)h = Height of conductor above ground,

in feetr = Radius of conductor in feet138 = Constant from L and C values in

Henries and Farads per mile

Z = = 138 log ohmsLC

2hr

above ground and its size (Westinghouse T&DReference Book, 1964).

Reducing the surge impedance of the neutralwould be desirable as an additional way to re-duce the amount of surge current diverted to theunderground neutral/ground system. Unfortu-nately, its wire size is set by system requirementsand reducing the height above ground is not anoption. For these reasons, the overhead neutralis not a major factor in mitigating the effects ofsurges on the underground system. However, itis a vital part of the overhead neutral/groundsystem that acts with arresters to prevent light-ning surges from propagating long distancesfrom the strike point.

It should be noted here that some lightningstrikes are of such a magnitude that distributionvoltage systems cannot be effectively protectedfrom them. However, the majority of lightningoutages and damage are caused by inducedlightning strokes (approximately 95 percent),which can almost always be eliminated byeffective lightning protection (including arresterprotection, line configuration, and system BIL).

Factors AffectingCable GroundingSystemPerformance

UNDERGROUND CABLE SYSTEMCONFIGURATIONThe function of the cable grounding system isto keep its entire length at ground potential atall times. Its ability to perform this functionunder fault and surge conditions is determinedby the resistance of its electrical connections toground. Ground resistance can be approximated

by calculation. The resistance of an actual instal-lation can be found only by measurement. Thetype of cable used—BCN, jacketed, or semicon-ducting jacketed—will determine the effective-ness of the grounding system in performing itsintended function.

Getting a low ground resistance can be diffi-cult and is highly site-specific. A question often

178 – Sect ion 5

asked about system grounding is, “How lowdoes the ground resistance have to be before itis considered a good ground?” Answering thequestion with a specific ohmic value is difficultbecause many variables are involved in an ap-plication. A low riser pole ground reduces thejacket voltage on jacketed cable. A low pad-mounted transformer ground—compared withthe service ground—reduces surge voltage onconsumer appliances. For JCN applications, theriser pole ground rod resistance should ap-proach 10 ohms, if practical, whereas the trans-former ground can have a higher value.

The system configurations of bare concentricneutral, semiconducting jacketed, and jacketedconcentric neutral cables affect grounding sys-tem performance. Because ground rods are the

5predominant way to obtain grounds at riser poles,intermediate points, and transformers, this sub-section reviews elements affecting their resistanceand required quantities. Soil resistivity also di-rectly affects the resistance of a ground electrode.

Bare Concentric Neutral CableDirect-buried, BCN cable is considered the idealconfiguration for a multigrounded neutral on afour-wire grounded-wye distribution system.Maximum continuous contact area between thesystem neutral and soil ensures an effectivelygrounded system. Correct operation of surge ar-resters is ensured under all conditions. Effectivegrounding limits neutral-to-ground voltages dur-ing faults and surge events, which reduces stresson cable insulation. The highest degree of pub-lic safety is also obtained. Unfortunately, corro-sion problems associated with the BCN cableconfiguration preclude its continued use in newinstallations.

Solid grounding by the BCN means the riserpole ground rod resistance has little effect oncable system surge protective levels. BCNs on di-rect-buried cable provide an effective path toground under most conditions. The concept is il-lustrated in Figure 5.9. The overall ground resis-tance measured along the cable is significantlylower than the driven ground. With two arresterdischarge paths available, a poor riser poleground merely means more surge current flowson the BCN, where it quickly goes to ground.

Although no longer in use by cooperatives,BCN cable relieved most but not all groundingconcerns for direct-buried systems. Putting thecable in nonmetallic conduit led to a lack ofcontinuous grounding and problems associatedwith poor grounding. Burying the exposed neu-tral in soil with different resistivities caused theneutral to corrode to the point where it was lostcompletely. Besides the reduction in groundingefficiency, open neutral wires caused localizedelectric field stresses. Over time, the insulationshield deteriorated, causing primary cable faults.The neutral wires of BCN cables were also moresusceptible to damage during cable pulling andinstallation.

In recent years, all utilities have experiencedpremature failures with direct-buried BCN cables.

Overhead PhaseConductor

Multigrounded Neutral

MOVArrester

LightningCurrent

Ground Rod

Bare Concentric Neutral UD Cable

Surge Current on BCN Dissipated in Earth

FIGURE 5.9: BCN Cable Riser Pole Installation Surge ArresterDischarge Paths.


Resulting investigations foundthe primary causes to be elec-trochemical treeing in cableinsulation and BCN corrosion.Accelerated tree growth waspinned to moisture in the in-sulation layer and high-voltagestress. As noted, these findingsled the RUS to change Bulletin 50-70 (U-1) to re-quire insulating jackets and thicker phase insulationon all underground cables. Addition of the jacketis a change from the BCN system configuration.

Semiconducting Jacketed CableAccording to tests conducted by General ElectricCompany for NRECA and various utilities, theconcentric neutral-to-ground voltage of semicon-ducting jacketed cable is essentially independentof riser pole ground rod resistance and arresterdischarge current. The semiconducting jacket actslike a BCN to provide good system groundingcharacteristics for underground installations. Toprovide good grounding, the semiconductingjacket must have a radial resistivity of less than100 ohm-m (see 2007 NESC Rule 354D2c). If thisjacket resistivity requirement is met, intermediategrounding for the cable run is not required. Un-fortunately, this is not true for an insulating jacket;additional effort must be made to approach thesame grounding system performance level achiev-able with semiconducting and BCN cable.

Insulated Jacketed CableAn insulating, protective jacket provides manybenefits. An exterior jacket provides mechanicalprotection for the neutral during pulling and in-stallation. The jacket isolates the copper neutralfrom contact with corrosive soils. This isolationprevents galvanic cell formation and inevitableneutral corrosion. A protective jacket offers sig-nificant mechanical protection to the insulationshield and primary insulation. It also delaysmoisture from reaching and damaging the insu-lation layer, increasing cable life. However, insu-lating the neutral from ground has somedrawbacks. The most important is that the per-formance of the grounding system is reduced.

Jacketed cable installations less than 1,000feet long would normally have their neutrals

grounded only at both ends ofthe cable. This type of systeminstallation will decreasegrounding quality when com-pared with a bare neutral con-figuration. For example, con-sider two 1/0 AWG, single-phase, direct-buried cable runs

of jacketed and BCN cables, 1,000 feet long, insoil of 100 ohm-m resistivity. The resistance-to-ground of the bare neutral cable, assuming a ca-ble effective diameter of 1 inch, is as follows:

If the jacketed neutral is grounded by single10-foot ground rods at each end with diametersof 3/4 inch, each rod would have a resistance ofthe following:

To meet safety codes, the BCN cable must beconnected to ground rods at each end as well.Adding the two ground rods to the BCN cablegives a total ground resistance for the installation.Note: Conductance (siemens), which is the

reciprocal of resistance (ohms), will be used inthe calculation to avoid the cumbersome for-mula for three resistances in parallel. Conduc-tances of individual grounds in parallel can becombined by simple addition:

For this particular example, the JCN cable in-stallation has resistance equal to the two groundrods in parallel or 16.07 ohms; therefore, theJCN cable has the following:

5Insulated jacket

reduces grounding

system performance.

1.15 siemens per 1,000 ft =0.87 ohms for a 1,000-foot cable (from Table 7.6)

32.14 ohms or 0.0311 siemens(from Equation 5.9)

11.2122

= ohms = 0.8249

0.0311 + 0.0311 + 1.15 = 1.2122 siemens

16.07 ohms ÷ 0.8249 ohms = 19.48 times theground resistance of a BCN cable installation

180 – Sect ion 5

In the preceding case, both systems would beconsidered adequately grounded according tocode. However, for longer runs or in higher re-sistivity soil, the jacketed cable would not be ad-equately grounded. Additional driven groundscould be added at both ends. For longer runs,the NESC requires at least four grounds in eachmile, not counting rods at indi-vidual services. To meet thisrequirement, the jacketed neu-tral must be attached togrounds at intermediate pointsalong the route.

DRIVEN GROUND RODS ON THE UD SYSTEMGround rods are the predominant type of madeelectrode on underground distribution systems.They are mainly used at the following:

• Riser poles,• Jacketed cable intermediate grounding points,• Cable joints,

5

FIGURE 5.10: Ground Rod Being Driven byHydraulic Tool.

• Pad-mounted transformer locations, and• Service entrances.

Ground rods normally carry high current onlyafter faults or lightning arrester operation.

Ground rods must be driven into undisturbedsoil. They should not be placed in the hole with

the riser pole or driven intobackfill around an installationsite. Loose soil will not pro-vide the necessary rod inter-face contact required for goodgrounding. Rods should bedriven at least 2 feet from

structures, concrete foundations, and poles withsteel reinforcing to prevent the possibility of arc-ing from the rod. See Figure 5.10.

Almost any metallic material may be used tomanufacture ground rods. Copper-clad and gal-vanized steel are most common. The measuredresistance of the rod in the ground is the mostimportant feature to consider. Rod material haslittle effect. Economics and corrosion considera-tions normally determine which rod materialis selected.

The ground resistance of driven rod(s) isaffected by various elements. There are severalways to improve existing ground resistance.Only the measured 60-Hz resistance will beconsidered here because surge impedance hasalready been reviewed. The number of rodsnecessary for good grounding practice and re-quired by the NESC is discussed here. Specificequations for calculating rod ground resistancefor various configurations and examples aregiven later in the System Ground ResistanceMeasurement and Calculation subsection.

When multiple ground rod sections arestacked on top of each other, a problem thatcan affect the ground rod resistance generallyoccurs. This problem is the lack of good soilcontact. Because of the larger diameter of thecoupling, the bottom ground rod is often theonly rod making full contact with soil. The firstcoupling opens up a hole larger than the groundrod body and subsequent ground rod bodiesmake very little contact with the soil, and aredefinitely not in contact with undisturbed soil.This lack of contact with the soil (disturbed or

Drive ground rods

into undisturbed soil.


undisturbed) can make a big difference in theresistance reading observed. As time passes andthe soil fills in around the ground rod body, theresistance values will change and most likely im-prove. The time required for this improvementis dependent on soil porosity, soil plasticity, andthe amount of moisture in the soil.

Ground Resistance of Driven RodsThe ground resistance of a rod (or group of rods)is found by measuring it with a ground resis-tance tester. Resistance calculations can be madefor specific installations and ground rod configu-rations to estimate what the resistance will be.Any theoretical calculations must start with thebasic equation in Equation 5.1 or its equivalent.Equation 5.1 shows that the ratio between thelength and area of the current path must be multi-plied by the soil resistivity, ρ. The resistivity thenaffects the ground resistance of any electrodesystem, such as a single ground rod, BCN, or

5

Equation 5.3

where: ρ = Soil resistivity, in ohm-mL = Rod length, in metersa = Rod radius, in meters

R = In (ohms); where L » a–1ρ

2πL4La

substation ground mat in the same way.Soil resistivity depends on soil composition.

Experience has shown that resistivity can varywidely over a relatively small area. This variationthroughout the soil volume cannot be modeledeasily in ground resistance calculations. All for-mulas developed in this section for ground elec-trode resistances assume soil resistivity is con-stant throughout its volume. This restriction mustbe considered when the results from formulasare interpreted. Elements that affect soil resistiv-ity are given later in this section.

The three primary factors that affect the groundresistance of ground rods that the engineer caninfluence are the following:

1. Length,2. Rod number, and3. Spacing.

Resistance Variation with DepthHow the resistance of a single ground rodvaries with length can best be demonstratedby considering itsresistance formula expressed by Equation 5.3.(Note that this formula assumes full contact ofall rod sections to the soil.)

Resistance does not decrease directly withlength. The actual variation can be seen in Fig-ure 5.11, which plots resistance against rodlength. The curves are drawn for an earth resis-tivity of 250 ohm-m.

A handy approximation that generally can beused is that doubling the rod length lowers theresistance by only 40 percent. For example, as-sume an eight-foot rod with a diameter of 5/8inch has a measured resistance of 90 ohms.Doubling the length to 16 feet will reduce theresistance to about 54 ohms, 90 – (0.4 × 90),

FIGURE 5.11: Resistance of Vertical Ground Rods as a Function ofLength and Diameter (Soil Resistivity = 250 Ω -m).

11

10

100

5/8"3/4"

1-1/4"

1000

10

Length of Ground Rod (Feet)

Resistance(Ohms)

100 1,000

182 – Sect ion 5

which agrees closely with the 5/8-inch curve ofFigure 5.11. Doubling the length again to 32 feetwould give a resistance of about 32 ohms, or54 – (0.4 × 54). As the rod length keeps increas-ing, the law of diminishing returns applies. Ad-ditional length produces a very small reductionin ground resistance. For the 5/8-inch rod of theabove example, this point of diminishing returnsoccurs at about 40 or 50 feet.

Resistance Variation withDiameterAnother way to lower groundresistance is to use a larger di-ameter rod. Doubling a rod’sdiameter reduces its resistanceby less than 10 percent. Themultiple rod diameter curvesin Figure 5.11 show the effect,which is minimal. Normal rod diameters usedon distribution systems are 5/8 inch and 3/4inch. In most instances, increased rod diameteris considered only when encountering hard soilor for driving deep rods connected to substationground mats.

5

FIGURE 5.12: Resistance of Multiple Ground Rods (Single Rod Equals 100 Percent).

Multiple Rods in ParallelReduced ground resistance can be obtained byparalleling rods to increase the cross-sectionalarea of the current path. Two identical rods dri-ven into soil some distance apart will not haveone-half the resistance of a single rod. The actualground resistance will be about 60 percent. Thereduction is about 40 percent for three rods inparallel and 33 percent when four rods are used.

These relationships hold truefor rods spaced about the samedistance apart as their length.

When multiple rods are ac-tually applied, the separationdistance should be at leasttwice the length of one rod.The increased separation isneeded to get the most usefuleffect of rod spacing. Figure

5.12 shows that, for rods spaced greater than20 feet apart, the reduction of the ground resis-tance falls off rapidly. For example, assume asingle rod 10 feet long with a measured groundresistance of 60 ohms. Four rods spaced 20 feetapart would have an equivalent resistance of

Use a longer rod,

not multiple rods,

to lower ground

resistance.

0 1 2 3 4 5 6 7 8 9 10100%

70%60%50%

40%

30%

25%

20%

100-Ft Spacing

Number of Ground Rods

ResistanceofMultipleGrounds

40-Ft Spacing20-FtSpacing

10-Ft Spacing

5-Ft Spacing


multiple rods or a deep-driven rod should be used.Long rods can be hard todrive in soil with a high rockcontent. Multiple rods cantake up a lot of area. If thedecision is made to install arod grid, the rod arrangementis less important than the

separation distance. The conductor length andnumber of connections should be kept to aminimum to tie the rods to the pole groundconductor. Two types of multiple rod groundinglayouts are shown in Figures 5.13 and 5.14 for ariser pole application.

Number of Driven RodsThe NESC (ANSI C2) does not specify thenumber of ground rods at specific locations onunderground cable systems. It also does not rec-ommend what the ground resistance should beat any specific location. But the NESC does havecertain requirements for JCN installation ground-ing methods that apply to BCN installations aswell. See the summary in Table 5.2. Specificlocations for driven rods are the following:

5

FIGURE 5.13: Installation of Three Rods for a Riser PoleGround. Source: Parrish, 1982.

FIGURE 5.14: Installation of Four Rods for a Riser PoleGround.

2' min.L

2L min.Cable

RiserConduit

Pole GroundConductor Vent

2' min.

L

2L min.

2Lmin

.

Cable

RiserConduit

Pole GroundConductor Vent

0.3 × 60 = 18 ohms. As theseparation distance approachesinfinity, the resistance of thefour rods will equal 15 ohms.

If geological conditionspermit, a single, deep-drivenrod should be used instead ofmultiple rods to lower groundresistance. For example, if four10-foot ground rods are placed 2 L apart (whereL is the length of the rod), they will have aboutthe same resistance as a 40-foot rod. If the sepa-ration distance is less than 2 L, the deep rod willprovide a much lower resistance than 4 × 10feet of rod placed close together.

The above statements are based on a homoge-neous soil profile. A deep rod will be expectedto reach the permanent water table beneath theearth. The resistivity at this level will be consid-erably lower than near the surface. The advan-tage of the deep rod will be more pronounced inthis case. Another benefit is that soil resistivity atgreater depths will not vary as much because ofchanges in temperature and moisture content aswill resistivity near the surface.

Site conditions will normally dictate whether

The NESC governs

ground rods for JCN

cable installations,

where practical.

184 – Sect ion 5

• Riser poles,• Pad-mounted transformers,• Joints/intermediate grounding points, and• Service entrances.

Pertinent NESC sections are the following:

• Section 9: Grounding Methods for ElectricSupply and Communication Facilities, and

• Part 3: Safety Rules for the Installation andMaintenance of Underground Electric-Supplyand Communication Lines.

Riser PolesRule 92B2b(2) says that a grounding conductormust be connected at the termination points of anonjacketed cable. Additional grounding pointsfor jacketed cable are recommended in 92B2b(3)since the neutral is not exposed and is not pro-viding a ground connection. For a typical UD in-stallation, the first termination point is the riserpole. If a driven rod is used, Rule 94B2a saysthat the total length may not be less thaneight feet. Minimum rod cross-sectional areasare also given. If longer or multiple rods areneeded, a minimum six-foot spacing is required.

A counterpoise is also considered a made elec-trode if the following conditions are met:

• The bare wire is No. 6 AWG or larger,• The length is greater than 100 feet, and• The counterpoise is laid in the same trench as

the buried cable (Rule 92B3).

There is no suggested value for ground resis-tance at the riser pole. It is noted in Rule 96Cthat multigrounded systems extend over a largearea and depend on a number of electrodes forgrounding purposes; therefore, no specific val-ues are imposed for the resistance of individualelectrodes.

As already mentioned, the lowest practicalground resistance should be obtained at theriser pole. As explained previously, low resis-tance ensures a low jacket voltage and preventsexcessive surge currents flowing to remotetransformer and service grounds. For minimaleffect on the system, a good goal is to have thelowest ground at the riser pole. The next highestground should be at the first pad-mounted trans-former. The highest ground resistance comparedwith the previous two should be at the serviceentrance.

5Location Rule Comment

Riser Poles 92B2b(1) Concentric neutral must be connected to surge arrester grounds wherecables are connected to overhead lines

94B2a If a driven rod is used, minimum length is eight feet and minimumdiameter is 5/8 inch for steel and 1/2 inch for copper-clad. Longer rodsor multiple rods may be used to reduce ground resistance.

94B2b Minimum spacing between multiple rods is six feet.

94B2c Driven depth not less than eight feet, with exceptions.

Pad-Mounted 93C7 and 314 Concentric neutral and pad-mounted transformer and other equipmentTransformers cases must be connected to a ground rod.

94B2c (exception) If the rod is placed within the pad-mounted enclosure or pedestal, drivendepth can be 7-1/2 feet.

Joints/Intermediate 96C Concentric neutral must be connected to ground rods at least four timesGrounding Points per mile (service grounds not included).

354D3c For random separation with communications cables, grounding interval iseight times per mile (service grounds not included).

Note. Consult the specific NESC rules cited in the text to avoid any misunderstandings caused by condensingthe rules in this table.

TABLE 5.2: 2007 NESC Ground Rod Requirements for JCN Cable Installations.

Pad-Mounted TransformersThis subsection covers only pad-mounted transformers. However, sug-gestions or recommendations are validfor any aboveground enclosure.

Rule 314 says that conductive partsmust be grounded, including cases ofpad-mounted devices. Because the neu-tral is brought to the transformer, it mustbe connected to a ground electrode ac-cording to Rule 96C. If a rod is usedwithin the footprint of a pad-mountedenclosure, an exception to Rule 94B2cstates that its driven depth may be re-duced to not less than 7-1/2 feet.

Pad-mounted transformers are nor-mally grounded with one driven rod,except in areas of high soil resistivitywhere up to four rods might be needed.The resistance of the transformerground should be less than the ground

at the consumer’s service entrance to ensure neu-tral surges are not transferred to wiring inside theresidence. Most cooperatives do not have controlover the value of the service ground. The engi-neer should make a survey of existing grounds inthe area. After a representative value is found, atarget for transformer and riser pole grounds canbe determined.

Figure 5.15 shows a typical grounding assem-bly for a single-phase, pad-mounted transformer.A continuous ground conductor loop is shownthat ensures solid grounding if one connectionfails. Two clamps are shown for the ground rod.These are recommended to prevent a high-resis-tance contact when two wires are connected withone clamp and to maintain ground electrode ef-fectiveness if one connection is defective.

Two, three, or four rods are sometimes usedto obtain the proper ground resistance at a trans-former. The separation distance between rodsshould be kept to at least twice the burial depthwhen possible. In some instances, installing afour-point grounding grid will obtain a lowground resistance and minimize the touch po-tential between case and ground. Figure 5.16shows a typical layout. The ground conductorshould be a continuous wire connected to twopoints on the transformer.


5

FIGURE 5.15: Grounding Assembly for Pad-Mounted Single-Phase Transformers.

FIGURE 5.16: Grounding Grid for Pad-Mounted Equipment Installation.

Ground Strap

#4 CopperGround Wire

Ground Rod Clamps

Opening

Top View

Front View Pad

Note3

GUIDELINE ONLY

GUIDELINE ONLY

Transformer Installation(Front View)

Tank Grounds

Note 1

H1B

H1A

X2

X1

X3

7'6"min.

8'0"min.

Jumper #4 Copper

Tamp Well Under Pad

Note:1. Tie concentric neutrals together before tap to ground

loop to ensure same conductivity as cable neutral.

Notes:1. Place minimum of one ground rod at each corner to obtain low ground resistance of

grounding grid. Minimum distance between ground unit assemblies = 6'0".

2. Grounding grid 1/0 AWG bare copper buried 18” minimum below ground. Run wireunder pad to opening and allow 5'0" for grounding live front switch/fuse enclosures.

3. Place ground wire a minimum of 24" away from the side or sides of pad that a personwould stand on to operate the equipment. The ground wire may be placed within 12"of the other sides.

18" min.

Figure 5.17 shows an instal-lation that could be used at ajacketed cable joint or inter-mediate neutral connection toground. These cable connec-tions are aboveground to pre-vent water from entering thejacket where the neutral isopened and sealed. An idealsituation is shown in which a

continuous ground conductor is used to bondthe neutrals together and to make up the groundloop to and from the ground rod.

Figure 5.18 shows a direct-buried installationthat could also be used at a jacketed cable jointor intermediate neutral connection to ground. Allthree neutrals are tied to ground by separateconductors attached to ground rods. Twojumpers are added between the cable phases toprovide a continuous grounding loop, so onefailed connection will not affect grounding. Theconnection to the concentric neutrals is madesimilar to the installation shown in drawingUM48-3 of RUS Bulletin 1728F-806 (D-806)dated June 2, 2000. This connection should beproperly sealed around the concentric neutral toprevent moisture entrance.

Figure 5.19 shows a direct-buried intermediategrounding assembly using in-line ground con-nectors. The principle is to strip the jacket froma short piece of cable, wrap a braid brazed to aconnecting rod around the concentric neutral,and seal the connection against moisture. Thedevice holds promise as a quick and simple wayto make an intermediate grounding point in acable run. Extreme care should be used with thistype of connection below ground so the jacket isadequately resealed to prevent moisture ingress.

The installations shown in Figures 5.17 and5.19 could be connected to three adequatelyspaced ground rods, if required for systemgrounding. Note that rods should be installedwith an inter-rod distance equal to two rodlengths for a reasonable degree of effectiveness.

Service EntranceNESC Rule 250-84 requires one driven ground rodat the service entrance to a residence. Ground re-sistance is to be 25 ohms or less. If the desired re-sistance is not obtained, one rod must be added.

186 – Sect ion 5

Joints/IntermediateGrounding PointsThe 2007 NESC does not callfor ground rods to be installedat direct-buried joints if theconcentric neutral is effectivelygrounded. However,Rule 92B2b(3) recommendsadditional connections be-tween the concentric neutraland ground for JCN systems. It also requires thatthe neutral be grounded at each cable joint that isnot otherwise insulated to the voltage expectedunder normal conditions. Because jacketed cablesystems are not as well grounded as BCN sys-tems, any joint or splice should be used as ameans for connecting the proper number of dri-ven ground rods to improve system grounding.

Rule 96C says that JCN must be grounded atleast four times per mile, not including groundsat individual services. Rule 354D says that, forrandom-lay installations with communication ca-bles in the same trench, there shall not be lessthan eight grounding installations in each mile,not including the service grounds. Intermediategrounding is not required for BCN cables orsemiconducting jacketed cables with jacket ra-dial resistivity less than 100 ohm-m.

5BCN and

semiconductingjacketed cablesdon’t need

intermediate grounds.

FIGURE 5.17: Installation of JCN Connection in Above-Grade Pedestal.

Ground Rod

JCN Cable Joint

GUIDELINE ONLY


As noted, the cooperative usually has no con-trol over the ground resistance at the meter base.To lessen the probability that incoming surgeson a JCN cable will cause damage to voltage-sensitive consumer equipment, ensure that theservice ground should have a value larger thanthe transformer ground. It is not practical for acooperative to check every service ground in itsterritory to determine its relative resistance valuecompared with other system grounds. However,if problems arise because of failed equipment inthe residence, the service ground would be alogical component to investigate.

One installation that will provide a resistanceto ground lower than the distribution trans-former ground is a service neutral tied to themetal casing of a domestic water well. In this in-stance, trying to reduce the system groundwould not be practical. Secondary metal oxidevaristor (MOV) arresters with low discharge volt-ages are a possible solution. The arrestersshould be installed as close to the protectedequipment as possible, preferably in the meterbase rather than at the transformer. Also, theconsumer should provide sensitive electronicequipment, such as personal computers, with in-dividual protection.

5

FIGURE 5.18: Grounding Assembly for JCN Underground Primary Cable.

FIGURE 5.19: Intermediate Grounding Assembly, UndergroundPrimary Cable.

GUIDELINE ONLY

Notes:1. #2 Thru 4/0 conductor—use #4 stranded copper ground

wire, 500 kcmil conductor—use #2 stranded copperground wire.

2. Engineer to specify number and length of ground rods.

3. Moisture seal around connections to the jacketed cableneutral. Use solid copper inside and extended throughmoisture seal.

4. Four grounds per mile minimum. More required with highground resistance.

5. Use this grounding assembly only with proper sealing onconcentric neutrals that prevent moisture permeating theinsulation.

Notes:1. #2 AWG to 400 kcmil conductor—

use #4 AWG solid copper ground wire.500 kcmil to 1,000 kcmil conductor—use #2 AWG solid copper ground wire.

2. Engineer to specify number and lengthof ground rod(s).

3. Adequate moisture seal must beprovided around connections tojacketed cable neutral.

4. It is recommended that connections toJCN be made above ground in anenclosure when feasible to preservemoisture integrity of jacket.

See Note 1

SeeNote 3

SeeNote 2

GroundingConductorSolid Copper(Continuous)#2–#4

as Required

In-Line Connecting Rod

Compression Connector

Moisture Seal

Ground Rod(s)

10’0”

Minimu

m

10’0”

Minimu

m

There is a method to esti-mate the ground resistance ofa counterpoise installation.Various aspects affect theground resistance of the con-ductor. A counterpoise pre-sents a surge impedance tothe flow of lightning current.

The impedance is different from the steady-stateground resistance. Surge impedance affects riserpole grounding and jacket overvoltage protec-tion. It is recommended that a continuous coun-terpoise be installed from the riser pole to thefirst transformer in the system.

COUNTERPOISE GROUND RESISTANCEThe steady-state, or R60-Hz, resistance to groundof a counterpoise electrode can be calculatedusing Equation 5.4.

188 – Sect ion 5

Counterpoise is not frequentlydiscussed in connection withBCN underground cable sys-tems. It is more often associ-ated with transmission linetower-footing surge resistancesand line outage rates causedby lightning. RUS requires co-operatives to install cable with an insulatingjacket. With increasing use of this cable, systemground quality is reduced in comparison withthe quality that could be had with BCN andsemiconducting jacketed cable. A counterpoiseis one method that will improve ground qualitywhen insulated JCN cable is used. It is a con-ductor buried in the ground as a practical meansto reduce ground resistance at a desired loca-tion. Lower ground resistance results from in-creasing the earth area in contact with thegrounding system. Installation of a counterpoiseis particularly simple on underground systemsbecause a trench is usually being opened.

5CounterpoiseApplication forInsulated JacketedCable

Use counterpoise

only for insulated JCN

cable installations.

FIGURE 5.20: Counterpoise 60-Hz Resistance Variation with Lengthand Different Soil Resistivities.

Equation 5.4

where: ρ = Soil resistivity, in ohm-m (Ω-m)L = Conductor length, in meters (m)a = Conductor radius, in meters (m)d = Burial depth, in meters (m)

R = In for d < L–1ρ

πL2Lad

Figure 5.20 shows how the resistance of a #4AWG copper wire varies with length in soils ofdifferent resistivities. Results are shown for burialdepths of 30 and 42 inches. When a counterpoiseis used only to improve surge arrester ground-ing, counterpoise lengths greater than 300 feetare not generally considered to be cost-effective.

Counterpoise can be extremely helpful whereupper layer soil resistivity is less than that of thesoil below. When rock layers prevent driving rodsof a suitable length to the proper depth, counter-poise may provide a workable alternative. So thatthe ground resistance does not vary widely duringthe year, special care should be taken to burycounterpoise below a stable moisture level. Bury-ing below the frost line must also be considered.An analysis of Equation 5.4 shows that depth

0 20 40 60 80 100 120 140 160

100 Ω-M

250 Ω-M

500 Ω-M

Counterpoise Wire5/16” Diameter, 3-Strand, Galvanized,Annealed Iron Wire. Burial Depth = 30”

180 200 220 240 260 280 300

Length (Feet)

60-HzResistance(ΩΩ)

0

10

20

30

40

50


does not dramatically affect counterpoise resis-tance. However, any increase in soil resistivitywill increase the ground resistance proportionally.

COUNTERPOISE SURGE IMPEDANCEWhen lightning current travels along a conduc-tor, the resistance it encounters is the surge im-pedance, not the steady-state resistance. Surge

5

FIGURE 5.21: Effect of Length on Transient Surge Impedance ofCounterpoise.

1 2 3 4 5

4

3

2

1

60 Hz Resistance

Z = 150-Ω Initial Surge ImpedanceR = 10-Ω 60 Hz Resistance

Curves: Counterpoise Length

1. 1,000 ft2. 750 ft3. 500 ft4. 250 ft

Microseconds (µs)

Surg

eIm

peda

nce

(Ω)

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

Equation 5.5

where: ZSURGE = Counterpoise surge impedance,in ohms

L = Conductor inductance, inHenries/unit length

C = Conductor capacitance, inFarads/unit length

ZSURGE = ohmsLC

impedance is usually designated by the symbolZSURGE and is expressed by Equation 5.5.

Transient or surge current initially “sees” thesurge impedance of the conductor, whether it ishung in the air, buried in the ground, or run ver-tically on a riser pole. A horizontal buried coun-terpoise has an initial surge impedance thatdepends slightly on soil conditions and is as-sumed to be about 150 ohms. As the wavefrontof a current surge travels along the conductor,more and more of its length helps to shunt thecurrent to ground. The final result is that, after aseries of reflections, the surge impedance re-duces to the steady-state resistance, R60-Hz. Thedecay time depends on the length of the coun-terpoise and the propagation speed of the surge.Depending on the dielectric constant of the soil,a surge travels at less than one-half the speed oflight (the speed of light is assumed to be 1,000feet per microsecond). Tests have shown that a1,000-foot counterpoise with an initial 150-ohmsurge impedance will reach a resistance equal toits steady-state value in about six microseconds(6 µs). A shorter counterpoise of 250 feet willhave the same 150-ohm initial surge impedance,but its steady-state resistance will occur in one-fourth the time (1.5 µs). Curves one to four ofFigure 5.21 show the relationship (WestinghouseT&D Reference Book, 1964).

REASONS FOR COUNTERPOISE USECounterpoise is buried with jacketed cable toreduce ground resistance at the point of applica-tion. Connection to the insulated cable neutralimproves grounding of the neutral and reducesoverall system ground resistance. If the counter-poise wire is run from the riser pole to the firsttransformer, it provides a parallel path for light-ning currents to flow to ground. The additionalpath diverts surge current from the pole groundand JCN. Less surge current in the ground roddecreases neutral-to-ground voltage and, thus,the jacket voltage. Lower jacket surge voltageswill reduce the probability of jacket punctureover time. Less current on the JCN means lesscurrent flowing to the transformer neutral.

How the surge impedance of counterpoiseaffects the pole ground and the jacket voltage isshown by Figure 5.22. Two possible counterpoiseconfigurations are shown. One is a continuous

190 – Sect ion 5

counterpoise connected directly to the JCN atthe top of the pole and extending to the firsttransformer. The other is connected to the riserpole ground rod and extendsto a remote ground (RG/25) thatmeasures at least 25 times lessthan the pole ground (RG).

In the examples in this sec-tion, it is assumed an incominglightning surge with a set mag-nitude and rate of rise willproduce a certain voltageacross the cable jacket, with no counterpoise ap-plied. Any changes in the jacket voltage caused

by the addition of counterpoise will be less thanthe no-counterpoise case.

A full-length counterpoise connected to thepad-mounted transformer neutral puts its surge im -pedance in parallel with the transformer ground rod, cableconcentric neutral, and theservice neutral. The connec-tion ensures the jacket voltagewill be less at the transformerthan at the riser pole. The

parallel impedance reduces the surge currentflowing on the JCN from the riser pole and the

5

FIGURE 5.22: Counterpoise Application to Reduce Jacket Voltage.

Legend:

R = Riser pole ground conductor resistanceL = Riser pole ground conductor inductanceI = Surge current in riser pole ground conductorRG = Riser pole ground rod resistance

RG/25 = Remote ground rod resistance

ZSURGE = Counterpoise surge impedance

RT = Transformer ground rod resistance

RS = Service entrance ground rod resitance

MOVArrester

RiserPole

Cable Termination

Cable Jacket

ZSURGECounterpoise

ZSURGE/R60–HzCounterpoise

S2

100'

150'

S3

S1

R

L

RGRG25

RT RS

Dead-FrontMOV

ArresterPad-MountedTransformer

ServiceLoads

Always connect

counterpoise at the

top of the riser pole.


5EXAMPLE 5.1: No Counterpoise Added (Switches S1, S2, and S3 Open).

When a surge arrester conducts, lightning current will split between the poleground conductor and the JCN in proportion to their respective surge imped-ances. The surge impedance of the concentric neutral depends on the geom-etry of the cable and the dielectric constant of the jacket material. It will fallsomewhere between the 35-ohm cable surge impedance and the 150-ohmcounterpoise surge impedance. If the pole ground has a surge impedance ofless than 15 ohms, most of the current will be diverted to the ground rod. Onecomponent of the peak jacket voltage at the sending end of the cable is thenequal to the ground potential rise caused by surge current flow through theground rod. The jacket voltage at the transformer or receiving end of the cablewill not be the same as the sending end because the voltage on the cable neu-tral is determined by the respective currents flowing in each ground and the re-sistance of each ground. The receiving end voltage will always be the smallerof the two.

Another component of the neutral-to-ground voltage at the riser pole is the L di/dt voltage of the pole ground conductor. For the configuration depicted in Fig-ure 5.22, the total neutral-to-ground voltage can be represented by Equation 5.6.

EXAMPLE 5.3. Continuous or Full-LengthCounterpoise (Switches S1 and S3 Closed, S2 Open).

In Figure 5.22, the counterpoise is shown con-nected in parallel with the jacketed concentricneutral at both ends of the cable. With the coun-terpoise run to the top of the riser pole, its surgeimpedance is connected directly in parallel withthe surge impedance of the concentric neutraland the down-lead conductor. This connectionwill reduce the current to the pole ground. As aconsequence, it also lowers both the ground potential rise and the L di/dt component of the down-lead voltage. Connecting a continuouscounterpoise at the riser pole ground rod, as ex-plained in Example 5.2, will not give the same ef-fect. Test data have shown that connection ofcontinuous counterpoise to JCN cable near theriser pole arrester will reduce jacket voltages byup to 50 percent for fast-front waveforms and35 percent for slow-front waveforms (GeneralElectric, July 1990).

EXAMPLE 5.2: Attaching a 100-FootCounterpoise to the Riser Pole Ground Rodand the Other End to a Remote, SmallerResistance (Switch S2 Closed, S1 and S3Open).

This case represents laying counterpoise termi-nated in a ground rod or running a connection toan existing electrode to decrease 60-Hz grounding.Initially, the counterpoise will present a 150-ohmimpedance in parallel with the riser pole groundrod. For surge currents peaking in 0.5 to eightmicroseconds, the slight decrease in the groundresistance will reduce ground potential rise by afactor depending on the difference between themagnitude of the riser pole ground (RG) and the150-ohm surge impedance of the counterpoise.This counterpoise installation will not reducejacket voltages very much, but still should be con-sidered to improve system grounding.

For a standard 8 × 20 µs current waveform, maximum di/dt occurs during theinitial part of the wavefront. Laboratory tests have shown that the L di/dt com-ponent is usually less than the IR component and will peak before the surge cur-rent waveform peaks. Therefore, the peak neutral-to-ground voltage and, thus,the peak jacket voltage is caused mainly by the surge current magnitude: I (R + RG). Because R is less than RG, the jacket peak voltage can be accuratelyrepresented by the product of the pole ground conductor current and the surgeimpedance of the ground rod.

However, for steep-front currents peaking in less than two microseconds, theL di/dt voltage could exceed the IR component in the case of a low down-leadcurrent. The same could happen for a high di/dt and low ground surge imped-ance. In both cases, the L di/dt component would predominate and producepeak jacket voltage.

Vng = I(R + RG) + L di/dt

where: Vng = Riser pole neutral-to-ground voltage, in voltsI = Current in riser pole ground conductor, in amperesR = Riser pole ground conductor resistance, in ohmsRG = Riser pole ground rod 60-Hz resistance, in ohmsL = Pole ground conductor inductance, in Henriesdi/dt = Surge current rate of rise, in amperes per second

Equation 5.6

192 – Sect ion 5

amount of current on the service neutral. Thecounterpoise will also divert transformer MOVarrester current from the service neutral in caseof a high transformer ground resistance (RT). Italso improves the 60-Hz ground resistance at thepad-mounted transformer.

Although the previous discussion mentionedonly direct-buried JCN cable, very similar resultswill be obtained for JCN cable installed in conduit.

RECOMMENDATIONS FOR JACKETED CABLE

1. Obtain a low ground resistance (10 ohms orless is desired) at the riser pole for any jack-eted cable installation. This strategy is bestto reduce jacket voltages for all types ofsurges, fast-front or slow-front. The induc-tance of the pole ground conductor cannotbe reduced. A measured ground resistanceof 10 ohms or less is desired at riser poles.

2. Counterpoise will reduce jacket voltages tosome extent, regardless of the riser poleground resistance.

3. The counterpoise must be attached to theinsulated JCN at the top of the riser pole toobtain optimum jacket voltage reduction.

4. A continuous counterpoise should be in-stalled to the first transformer for every un-derground installation, if practicable.

5. If a full-length counterpoise cannot be justified economically, counterpoise of 100 to 300 feet should be installed at theriser pole, depending on soil resistivity and condition.

6. The conductor is to be random-lay in thesame trench as the cable. The counterpoisemust be surrounded by soil. A drivenground rod is used to terminate the coun-terpoise conductor. The rod is counted to-ward the four- or eight-grounds-per-mileNESC requirement.

7. Counterpoise will not significantly reducetouch potentials on jacketed cable installa-tions. Therefore, proper safety proceduresmust be followed.

5

System Ground Resistance Measurement and Calculation

FIELD MEASUREMENT OF SYSTEM GROUNDSTo correctly measure the resistance of a systemground, the engineer needs to understandground resistance. Ground resistance consists ofthe following:

• Resistance of the ground rod,• Resistance of the contact

between the ground rod andthe soil directly in contactwith the rod, and

• Resistance of the body ofearth surrounding theground rod.

The resistance of the groundrod and the contact resistanceare usually extremely smallcompared with the earth resis-tance. To understand earth re-sistance, think of the groundrod as being surrounded byconcentric shells of earth (seeFigure 5.23). These shells have

equal thickness; therefore, the shell nearest therod has the smallest surface area and conse-quently the greatest resistance. The farther theshell is from the rod, the greater the surfacearea, which results in a lower resistance in the

shell. At some remote point,an additional shell does notsignificantly add to the earthresistance surrounding therod. The final shell is consid-ered the effective resistancearea and depends on the dri-ven depth and the diameter ofthe ground rod.

Three-Point MeterA three-point ground resistancetester can measure the groundresistance of the following:

• A single ground rod,• Multiple ground rods, and• Small grids of ground

conductor.

The main component

of ground resistance

is resistance of the

earth surrounding

the ground rod.

To measure ground

resistance, use a

three-point or

clamp-on ground

resistance tester.


These measurements must be made beforethe ground rod or grid is connected to the sys-tem ground. Unfortunately, the tester cannotpractically measure the ground resistance of along counterpoise.

This ground resistance tester has three termi-nals as shown in Figure 5.24. The current (C)terminal and the potential (P) terminal are eachconnected to separate test probes. The third ter-minal (X) is attached to the grounding electrodethat is being tested. Figure 5.24 shows the correcttest setup. The tester injects a current throughtest probe C and grounding electrode X. The re-sulting potential drop is measured between testprobe P and grounding electrode X. The resis-tance reading shown on the test is the groundresistance of the electrode. This test procedure isknown as the Fall-of-Potential Method. For addi-tional information on this test method, see IEEEStandard 81.

During this test, it is important to space thetest probes and electrodes correctly. If the threeelectrodes are too close together, then the effec-tive resistance areas of probes C and X will over-lap (see Figure 5.25). This overlapping producesinaccurate resistance readings. For readings to

5

FIGURE 5.23: Earth Resistance.

FIGURE 5.24: Correct Ground Resistance Test Setup.

Current Current

GroundingElectrodeUnder Test

Effective ResistanceAreas Do Not Overlap

Resistance of Test Probe C

Resistance

62% of D

D

X P C

X P C

Resistance of Grounding Electrode

TestProbe

TestProbe

FIGURE 5.25: Incorrect Ground Resistance Test Setup.

GroundingElectrodeUnder Test

Effective ResistanceAreas Overlap

Resistance

Distance

D

X P C

TestProbe

TestProbe

194 – Sect ion 5

be correct, the spacing must be increased so theeffective resistance areas do not overlap. Table 5.3lists the recommended distances for probe Cwhen testing a single ground rod. Also listed arethe distances to the P probe.

Probe P is placed at 62 percent of the distancefrom the ground rod to the C test probe. Asshown in Figure 5.24, the 62 percent methodshould place the potential probe outside the ef-fective resistance area of the other two elec-trodes. The preferred placement for P is in astraight line between C and X.

To test multiple ground rods or small grids,increase the distance to the C probe. Table 5.4provides a list of recommended spacing for theC and P test probes.

The maximum dimension is the diagonal dis-tance across the electrode system area. For ex-ample, if four rods form a square with 20-footsides, the electrode system area is 20 feet × 20feet. This area has a diagonal of approximately28 feet. Using Table 5.4, choose the next highestmaximum dimension, which is 40 feet. The tableshows that P should be at 200 feet and C at 320feet. The preferred placement for P is still at 62percent of the total distance and is in a straightline between C and the electrical center of theelectrode system.

Most three-point meters have a resistancerange of 0 to 500 ohms and are accurate for testprobe resistance values of up to 5,000 ohms.Most newer models have an indicator to signalthe operator if the test probe resistance valuesare excessive or if there is a lack of continuitybetween the leads and the test electrode.

Clamp-On MeterAnother type of meter used to make ground re-sistance measurements is the clamp-on groundresistance tester shown in Figure 5.26. This in-strument clamps around a ground rod or groundconductor and displays a resistance reading. Un-like the three-point test, this measurement is madewith the ground rod or conductor still connectedto a multigrounded system. The tester contains aconstant voltage source that induces a currentinto the test ground. This current is detected andused to determine the resistance.

5Depth of Driven Rod (ft) Distance to P (ft) Distance to C (ft)

6 45 72

8 50 80

10 55 88

12 60 96

18 71 115

20 74 120

30 86 140

TABLE 5.3: Spacing of Test Probes for Testing Resistance of a SingleGround Rod. Source: AEMC Corp., 1990.

Maximum Dimension (ft) Distance to P (ft) Distance to C (ft)

2 40 80

4 60 100

6 80 125

8 90 140

10 100 160

12 105 170

14 120 190

16 125 200

18 130 210

20 140 220

40 200 320

60 240 390

80 280 450

100 310 500

120 340 550

140 365 590

160 400 640

180 420 680

200 440 710

TABLE 5.4: Spacing of Test Probes for Testing Resistance of anElectrode System. Source: Biddle Instruments, 1981.


Figure 5.27 shows a circuit diagram for amultigrounded system with the clamp-on testerin place. Rx represents the ground being mea-sured. R1 through Rn represent the remaininggrounds in a multigrounded system. Because theparallel combination of R1 through Rn is muchsmaller than Rx, most of the voltage drop isacross Rx. Therefore, the resistance reading onthe meter is basically the value of Rx.

To work properly, the meter must be clampedon a ground rod or conductor that has only onereturn path to the neutral. If the meter isclamped onto a ground loop, the induced cur-rent will circulate around the loop and the meterwill show a very low resistance reading. Placingthe clamp below the loop or disconnecting oneside of the loop forces the induced current toflow through the test ground (Rx). Ground loopsare often inside pad-mounted transformers.Here, several ground conductors and one ormore ground rods are bonded together. Clamp-ing the meter around the ground rod and belowthe common attachment point should allow anaccurate ground resistance reading of the rod.This test setup is shown in Figure 5.28.

This meter has a resistance range of two to1,990 ohms and a ground current range of zeroto 1.99 amperes. If the ground current exceeds1.99 amperes during the test, ground resistancemeasurements are not possible.

5

FIGURE 5.26: Clamp-On Ground Resistance Tester. Source: AEMCCorporation, 1992.

FIGURE 5.27: Circuit Diagram for Multigrounded System.

FIGURE 5.28: Ground Resistance Test Setup for Clamp-On Tester.

Ground Strap

Copper Ground Wire

Clamp-On Ground Resistance Meter(See Note 1)

Ground Rod Clamps

Front View of Transformer

Ground Resistance ofMultigrounded System

Ground Resistanceof Ground Rod thatis being Tested

E

I

R1RX R2 Rn–1 Rn

Tank Grounds

H1B

H1A

X2

X1

X3

Copper Ground Wire

Note:1. For best reading, clamp meter onto the ground rod itself,

below the point where ground conductors are attached.

196 – Sect ion 5

SOIL RESISTIVITYMEASUREMENTSIn addition to thermal resistiv-ity (discussed in Section 4 ofthis manual), soil has an elec-trical resistivity. The electricalresistivity is the resistance of aunit cross-sectional area of soilper unit length and is ex-pressed by Equation 5.7.

5

Equation 5.7

where: ρ = Soil resistivity, in ohm-mR = Resistance, in ohmsA = Cross-sectional area, in meters2

L = Length, in meters

ρ= R × AL

Soil resistivity directly affectsthe resistance-to-ground of agrounding electrode. Knowingthe soil resistivity for a particu-lar site allows the engineer todesign adequate grounding forthe underground cable system.The cooperative may havesoil resistivity data from tests

conducted at substation sitesor along transmission lines. Ifthe cooperative engineer doesnot have soil data for the areaof underground cable installa-tion, then soil resistivity mea-surements may be necessary.After the engineer collects soildata from different areas, hemay be able to assign approxi-mate resistivity values through-

out the service territory. It will probably becomeapparent that each different soil type present inthe service area has a relatively narrow range ofresistivity. These approximate values can beused instead of measuring the soil resistivity forevery underground system that is to be installed.

Four-Point MeterMeasuring soil resistivity requires use of a four-point earth resistance tester. This tester is similarto the three-point tester and can be used to mea-sure the resistance-to-ground of a ground elec-

trode. However, the three-point tester will not measuresoil resistivity. The four-pointtester is more sensitive than thethree-point tester, measuringvalues as low as 0.01 ohms. Asevident from the name, thefour-point tester has four ter-minals instead of three (seeFigure 5.29).

Measuring soil resistivity requires that four testprobes be driven in the ground. The test probesmust be equally spaced and in a straight line asshown in Figure 5.29. It is important that all testprobes are driven to the same depth. A depth ofsix to 18 inches is acceptable. Equally important,the test probes must have good soil contact.Loose test probes can lead to erroneous readingsbecause of high probe resistance.

The tester continues the test setup by placingtest leads from the four terminals to the four testprobes. The two current terminals (C1 and C2)connect to the two outer test probes. The twopotential terminals (P1 and P2) connect to thetwo inner test probes. Figure 5.29 also illustratesthese connections. The tester injects a currentinto the two outer probes and measures the

Knowing the soil

resistivity helps in

the design of an

adequate grounding

system.

Use a four-point

earth resistance

tester to measure

soil resistivity.

FIGURE 5.29: Setup for Soil Resistivity Test.

C1 P1 P2 C2

C1 P1 P2 C2

Small-SizedElectrodes

a

b

a a


corresponding potential drop between test probesP1 and P2. Using these two values, the tester de-termines the resistance. This resistance value iswhat the operator reads when making soil resis-tivity measurements. (For more information onthis test method, refer to IEEE Standard 81-1983.)

Most four-point testers give indication of highprobe resistance. If an operator gets this indica-tion, he should first check to see if test probesare secure in the ground. If test probes areloose, the operator needs to drive rods deeperor relocate one or more rods. If the tester stillshows high probe resistance, then the operatorneeds to pour water around each test probe tohelp reduce the test probe resistance so mea-surements can be made. Test accuracy will notbe affected if the probe spacing significantly ex-ceeds the diameter of the wetted area.

The resistance value shown on the four-pointtester is a function of the apparent soil resistivity.

This apparent resistivity is the average resistivityfor a block of soil with a depth equal to thespacing between the test probes. For example, ifthe test probe spacing is five feet, then the resis-tance reading is the average resistivity to a depthof five feet. To get a complete soil profile, theoperator needs to take measurements at variousprobe spacings.

Elements Affecting Soil ResistivitySeveral elements affect soil electrical resistivity,including the following:

• Soil type,• Moisture and chemical content,• Temperature, and• Seasonal variations.

Different soil types have different resistivityvalues, as shown in Table 5.5.

5

Cretaceous Cambrian Precambrian Earth Resistivity Tertiary Carboniferous Ordovician and Combination

(ohm-m) Quaternary Quaternary Triassic Devonian w/Cambrian

1 Sea Water

Loam

10 Unusually Low Clay

Chalk Chalk

30 Very Low Trap

Diabase

100 Low Shale

Limestone Shale

300 Medium Sandstone Limestone

Sandstone Sandstone

1,000 High Dolomite Quartzite

Coarse Slate

3,000 Very High Sand and Granite

Gravel in Gneiss

10,000 Unusually High Surface

Layers

TABLE 5.5: Soil Resistivities for Different Soil Types and Geological Formations. Adapted fromIEEE Standard 81-1983.

198 – Sect ion 5

Moisture and chemical con-tent dramatically affect soilresistivity. The moisture dis-solves the naturally occurringsalts in the soil. The resultingelectrolyte improves the con-duction of current through thesoil and, thus, reduces the soilresistivity. As the moisture

content increases, the soil resistivity decreases.This decrease is rapid until the moisture contentreaches 20 percent to 30 percent (see Figure5.30). The amount of dissolved salt that is pre-sent in the soil also affects the resistivity. As thesalt content increases, the resistivity decreases.However, the decrease in resistivity is minimalafter the salt content reaches five percent. Thegraph of Figure 5.31 shows the effect of salt insoil that contains 30 percent moisture.

A third element affecting soil resistivity is tem-perature. Temperatures above freezing have littleeffect on resistivity. However, as the temperaturedrops below freezing, the soil resistivity increasesrapidly. To illustrate this effect, Table 5.6 shows

5

FIGURE 5.30: Effects of Moisture on Soil Resistivity. Adapted from IEEE Standard 80-1986.

0 5 10 15 20 25 30 35 40 45

10,000

5,000

1,000

500

100

50

Soil Resistivity (ΩΩ-m)

Percentage Moisture

FIGURE 5.31: Effects of Salt Content on Resistivity in Soil Containing30 Percent Moisture. Adapted from IEEE Standard 80-1986.

1 2 3 4 5 6 7 8 9 10

10,000

5,000

1,000

500

100

50

Soil Resistivity (ΩΩ-m)

Percentage Salt

Typically, the earth surfaceis composed of layers of different soil types. These soiltypes have varying resistivities;therefore, soil resistivity mea-surements often show differentvalues at different depths.

An increase in

moisture and salt

content decreases

soil resistivity.

Soil resistivity varies

as a result of

seasonal changes.

Temperature Resistivity

°C °F (ohm-m)

20 68 72

10 50 99

0 32 (water) 138

0 32 (ice) 300

-5 23 790

-15 14 3,300

TABLE 5.6: Effect of Temperature on SoilResistivity. Adapted from Biddle Instruments,1981.

If the depth (b) of the probes is small (fivepercent of the probe spacing), Equation 5.8 reduces to

The resistivity values can be plotted against thetest probe spacings. This information is neededto determine an appropriate soil model.

SIMPLIFIED DESIGN OF GROUNDING SYSTEMUSING RESISTIVITY DATAResistance-to-ground (ground resistance) calcula-tions can be used when a grounding system isdesigned. Using these calculations, the engineercan compare the ground resistance of severalground electrode configurations:

• A single ground rod,• Groups of ground rods, and• Counterpoise.

The ground resistance of an electrode is afunction of the soil resis-tivity and the electrodegeometry. Therefore, thecalculations requireknowledge of the soil re-sistivity. If the soil resistiv-ity is unknown, theengineer can get this in-formation from a soil re-sistivity test as describedearlier in this section.


how temperature affects the resistivity of sandyloam that contains 15.2 percent moisture. At thefreezing point, the resistivity more than doubles.

Soil temperature and moisture content usuallyvary throughout the year. As a result, soil resis-tivity also varies throughout the year. Thesechanges must be considered when the ground-ing for an underground system is designed. Theground resistance of a counterpoise increases ifthe soil around it freezes during the wintermonths. Table 5.6 shows that the soil resistivityincreases from 138 to 300 ohm-m at the freezingpoint. This change produces a proportionalchange in the ground resistance of the counter-poise. A counterpoise with a ground resistanceof 38 ohms in the summer could increase to 83ohms when the ground freezes. The counter-poise should thus be buried below the frost line.Likewise, ground rods should be driven to adepth that is below the frost line.

In some areas, the summer months are oftendry. As the soil around the grounding electrodedries out, its ground resistance increases. If theloss of moisture increases the soil resistivity by50 percent, then the ground resistance of theelectrode will also increase by 50 percent. Resis-tance increase caused by loss of soil moisture isa major concern. A reduction of moisture con-tent from 25 percent to 15 percent can causeelectrode resistance to triple. Extending groundrods into an area with permanent moisture con-tent can minimize this problem. A rod that ex-tends into the water table has a more stableground resistance.

Because seasonal changes can affect soil re-sistivity, it is important to note the temperatureand the soil moisture content of the soil at thetime of a four-point soil resistivity test. This in-formation will help the engineer design agrounding system that performs ef-fectively throughout the year.

Equation for Deriving Resistivityfrom Resistance ReadingThe measurements made with afour-point tester are resistance val-ues. These resistance values mustbe converted to soil resistivity mea-surements using Equation 5.8.

5

Use ground resistance

calculations to

compare grounding

systems.

Equation 5.8

where: ρ = Soil resistivity, in ohm-mR = Resistance readings, in ohmsa = Spacing between test probes,

in metersb = Depth of test probe, in meters

ρ=

–1 +

4πaR2a

a2 + 4b2a

a2 + b2

ρ= 2πaR

200 – Sect ion 5

The most simple grounding electrode is a sin-gle ground rod. Equation 5.9 (Dwight, 1936)provides the ground resistance of a single rod.

The ground resistance of two ground rods inparallel separated by a distance, s, is given inEquations 5.10 and 5.11 (Dwight, 1936). If thespacing between the rods is greater than the rodlength (s > L), use Equation 5.10. If the spacingis less than the length (s < L), use Equation 5.11.

5

Equation 5.10

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Ground rod length, in metersa = Ground rod radius, in meterss = Distance between ground rods,

in meters

R = In –1ρ4πL

4La

+ 1– + ρ4πs

25

L2

3s2L4

s4

Equation 5.11

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Ground rod length, in metersa = Ground rod radius, in meterss = Distance between ground rods,

in meters

R = In –2 + ρ4πL

4La+ In

4Ls

– + s2L

s2

16L2s4

512L4

Equation 5.12

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Ground rod length, in metersa = Ground rod radius, in metersA = Area occupied by ground rods,

in meters2

K1 = Constant obtained from Figure 5.32n = Number of rods in the group

R = In –1 + ρ

2πnL4La

2K1LA

n – 1 2

Equation 5.13

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Length of counterpoise, in metersa = Radius of counterpoise, in metersd = Depth of counterpoise burial,

in meters

R = In –2 + ρ2πL

2La+ In

Ld

– + 2dL

d2

L2d4

2L4

Equation 5.14

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Length of counterpoise, in metersa = Radius of counterpoise, in metersd = Depth of counterpoise burial,

in meters

R = In –1ρπL

2Lad

Equation 5.9

where: R = Ground resistance, in ohmsρ = Soil resistivity, in ohm-mL = Ground rod length, in metersa = Ground rod radius, in meters

R = In –1ρ2πL

4La

The equation becomes more complicated forgroups of ground rods that are connected. In ad-dition to individual rod geometry, the area (A)occupied by the group of rods and a coefficient(K1) affect the equation. The coefficient K1 is re-lated to the geometry of the rod group and can


be obtained from the graph of Figure 5.32 orfrom the associated equation. Equation 5.12 provides the ground resistance of a group ofground rods (Schwarz, 1954).

Equation 5.13 provides the ground resistanceof a counterpoise (Dwight, 1936).

In underground system applications, thelength of the counterpoise is often much greaterthan the depth of burial. For these cases, a sim-pler equation, Equation 5.14, provides a suitableapproximation of the ground resistance value.

Examples 5.4, 5.5, and 5.6 illustrate how theground resistance of a grounding systemchanges for different configurations.

Increasing the number of ground rods is oneway to decrease the ground resistance. However,the spacing between the ground rods affectshow much the ground resistance decreases. Asthe separation increases, the ground resistancedecreases.

5

FIGURE 5.32: Coefficient K1 for Ground Resistance Calculations. Adapted from IEEE Standard 80-1986.

Curve A: For Depth h = 0

K1 = –0.04x + 1.41

Curve B: For Depth h =

K1 = –0.05x + 1.20

Curve C: For Depth h =

K1 = –0.05x + 1.13

Area10

Area6

1 2 3 4

Length-to-Width Ratio, X

Coefficient K

1

5 6 7 80.85

0.90

0.95

1.00

1.05

1.10

1.15

1.20

1.25

1.30

1.35

1.40

A

B

C

EXAMPLE 5.4: A Single 8-Foot × 3/4-Inch Ground Rod Driven in Soilwith a Resistivity of 250 Ohm-M.

To calculate the ground resistance, use Equation 5.9:

By substituting the values,

where: ρ = 250 Ω-mL = 8 ft (0.3048 m/ft) = 2.44 ma = .5 (.75 in.)(0.0254 m/in.) = 0.0095 m

R = In –1ρ2πL

4La

R = = 96.8ΩIn –1250 Ω-m2π(2.44m)

4 × 2.44m0.0095m

202 – Sect ion 5

The distance between the rods can be increased until there is no mutual resistance effect. The ground resistance of the two rods is equal to the parallel combination of two individual rods. Because two identical rods have the same ground resistance, the parallel resistance is one-half the single rod ground resistance.

For the two eight-foot by 3/4-inch groundrods, the limiting ground resistance value is

5EXAMPLE 5.5: Two 8-Foot × 3/4-Inch Ground Rods Placed 5 Feet Apart.

Because the spacing is less than the ground rod length (s < L), use Equation 5.11:


The addition of a second rod reduced the ground resistance from 96.8 to 57.7 ohms, approximately 40 percent. Ifthe two rods are spaced further apart, the ground resistance becomes even lower.

where:ρ = 250 Ω-mL = 8 ft = 2.44 m

a = 0.375 in.(0.0254 m/in.) = 0.0095 ms = 5 ft (0.3048 m/ft) = 1.52 m

R = In –2 + ρ4πL

4La+ In

4Ls

– + s2L

s2

16L2s4

512L4

R = In –2 + 250 Ω-m4π(2.44m)

4 × 2.44m0.0095m

4 × 2.44m1.52m

1.52m2 × 2.44m

(1.52m)2

16(2.44m)2(1.52m)4

512(2.44m)4+ In – + = 57.7Ω

EXAMPLE 5.6: Two Rods Spaced 16 Feet Apart.

For a spacing of 16 feet, use Equation 5.10:


The increased spacings reduced the ground resistance from 57.7 to 52.2 ohms.

where:ρ = 250 Ω-mL = 8 ft = 2.44 m

a = 0.375 in.(0.0254 m/in.) = 0.0095 ms = 16 ft (0.3048 m/ft) = 4.88 m

R = In + 250 Ω-m4π(2.44m)

250 Ω-m4π(4.88m)

4 × 2.44m0.0095m

(2.44m)2

3(4.88m)2– 1 +

(2.44m)4

(4.88m)41– = 52.2Ω

R = In –1ρ4πL

4La

+ 1– + P

4πs25

L2

3s2L4

s4

25

R = R1

where: R1 = 96.8 Ω

(96.8 Ω) = 48.4 Ω


This is not a significant improvement from the52.2 ohms at a 16-foot spacing.

12

R = 12


Another way to reduceground resistance is to increase the rod length. (See Example 5.8.)

Soil resistivity influencesground resistance. Ground resistance is directly propor-tional to soil resistivity; for ex-ample, a 20 percent decrease in soil resistivitydecreases the ground resistance by 20 percent.(See Example 5.9.)

The soil resistivity test mayshow that the soil has two lay-ers with different resistivityvalues. If a driven rod is incontact with the two layers, thenits ground resistance will differfrom the ground resistance inhomogeneous soil. If the lower

layer has a lower resistivity than the upper layerdoes, then driving a rod into the lower layer re-duces the ground resistance of the rod.

5EXAMPLE 5.7: Group of Four Rods.

FIGURE 5.33: Grouping of Four Ground Rodswith 16-Foot Spacing.

Using a grouping of four ground rods gives a more dramatic improvement. For thisexample, use the layout of Figure 5.33.

Using Equation 5.12,


The area occupied by the rods also affects the ground resistance. A smaller arearesults in a higher ground resistance. For example, consider the arrangement ofFigure 5.34. Here,

R = In –1 + = 42.2Ω250 Ω-m

2π(4)(2.44m)4 × 2.44m0.0095m

2(1.375)(2.44m)(1.52m)2

4 – 1 2

where:ρ = 250 Ω-mL = 2.44 ma = 0.0095 m

n = 4K1 = 1.375 (obtained from Figure 5.32)A = (4.88 m)2

R = In –1 + ρ

2πnL4La

2K1LA

n – 1 2

R = In –1 + = 29.8Ω250 Ω-m

2π(4)(2.44m)4 × 2.44m0.0095m

2(1.375)(2.44m)(4.88m)2

4 – 1 2

Increasing the

number of ground

rods decreases the

ground resistance.

Increasing the

number of ground

rods decreases the

ground resistance.

16 Feet(4.9 Meters)

16 Feet

(4.9 Meters)

FIGURE 5.34: Grouping of Four Ground Rodswith 5-Foot Spacing.

5 Feet(1.5 Meters)

5 Feet

(1.5 Meters)

Increasing the rod

length decreases the

ground resistance.

204 – Sect ion 5

Calculating the effect of a two-layer soil requires the use of an apparent soil resistivity,ρa, as defined in Equation 5.15.

Equation 5.15 is valid only when the groundrod is in contact with both soil layers (IEEEStandard 80-1986). The apparent resistivity, ρa,

5EXAMPLE 5.8: Increase in Rod Length.

Use Equation 5.9 to calculate the ground resistance of a 16-foot ground rod:


Doubling the rod length decreased the ground resistance from 96.8 (Example 5.4)to 54.0 ohms, a 44 percent reduction. If the ground rod length is 24 feet (7.32 m),then the following results:

where: ρ = 250 Ω-mL = 16 ft (0.3048 m/ft) = 4.88 ma = 0.0095 m

R = In –1ρ2πL

4La

EXAMPLE 5.9: Change in Soil Resistivity.

If the soil resistivity is 100 instead of 250 ohm-m, theresistance of a single eight-foot rod changes from 96.8(Example 5.4) to 38.7 ohms. This resistance can becalculated in two ways. The first uses Equation 5.9with ρ= 100 ohm-m:

The second method calculates R based on its directproportionality to ρ:

R250 = 96.8 Ω

Table 5.7 shows the ground resistance of a singleeight-foot by 3/4-inch ground rod driven in varying soilresistivities.

This table shows how difficult it is to achieve a lowground resistance with a single eight-foot ground rod.

R = In –1 = 54.0Ω250Ω-m2π(4.88m)

4 × 4.88m0.0095m

R = In –1 = 38.2Ω250Ω-m2π(7.32m)

4 × 7.32m0.0095m

This is a reduction of 61 percent. However, this calculation has used the assumptionthat the average soil resistivity is constant for eight-foot, 16-foot, and 24-foot rods.This is generally not the case. Soil resistivity often decreases substantially betweenthe surface and a depth of 24 feet.

R = In –1 = 38.7Ω100Ω-m2π(2.44m)

4 × 2.44m0.0095m

= R100R250

100 Ω-m250 Ω-m

R100 = 96.8 Ω = 38.7 Ω100250

Ground Resistance R Soil Resistivity (ohm) (ohm-m)

10 26

15 39

25 65

50 130

75 195

100 260

500 1,300

1,000 2,600

TABLE 5.7: Ground Resistance in VaryingSoil Resistivities.

Equation 5.15

where: ρa = Apparent resistivity, in ohm-mρ1 = Soil resistivity of top layer, in ohm-mρ2 = Soil resistivity of bottom layer, in

ohm-mL = Ground rod length, in metersH = Thickness of top soil layer, in meters

ρa = L(ρ1ρ2)

ρ2H + ρ1(L – H)

replaces the soil resistivity, ρ, in Equations 5.9through 5.12.

where:


5EXAMPLE 5.10: The Effect of a Tw0-Layer Soil with a Top-Layer Resistivity of 250 Ohm-M and a Bottom-Layer Soil Resistivity of 50 Ohm-M.

The top-layer thickness is 5 feet. Using Equation 5.15,

Substituting the values yields the following:

where: ρ1 = 250 Ω-mρ2 = 50 Ω-mL = 2.44 mH = 5 ft (0.3048 m/ft) = 1.52 m

ρa = L(ρ1ρ2)

ρ2H + ρ1(L – H)

ρa= =99.7 Ω-m2.44m(250 Ω-m)(50 Ω-m)

(50 Ω-m)(1.52m) + 250 Ω-m (2.44m – 1.52m)

where: ρa = 99.7 Ω-mL = 2.44 ma = 0.0095 m

R = In –1ρa2πL

4La

R = In –1 = 38.6Ω99.7Ω-m2π(2.44m)

4 × 2.44m0.0095m

R = In –1 = 14.4Ω66.6Ω-m2π(4.88m)

4 × 4.88m0.0095m

ρa = =66.6 Ω-m4.88m(250 Ω-m)(50 Ω-m)

(50 Ω-m)(1.52m) + 250 Ω-m (4.88m – 1.52m)

The value ρa replaces ρ in Equation 5.9:


Rod contact with the more conductive lower layer reduced the ground resistance of a single eight-foot rod from 96.8(Example 5.4) to 38.6 ohms. The lower layer is even more effective if a longer ground rod is driven. For example, a16-foot (4.88 m) rod changes ρa to

Equation 5.9 yields the following:

The presence of a more conductive lower layer reduced the ground resistance of a 16-foot rod to 14.4 from 54.0ohms, as calculated in Example 5.8.

206 – Sect ion 5

Examples 5.11, 5.12, and 5.13 calculate theground resistance of different counterpoise configurations.

A more conductive soil (a lower ρ) also reduces the ground resistance, as seen in Example 5.12.

The depth of burial (see Example 5.13) is another element that affects ground resistance.

5

A more conductive

soil reduces the

ground resistance.

EXAMPLE 5.11: Counterpoise of #2 AWG Conductor Buried 30 InchesDeep for a Distance of 100 Feet.

The burial depth is much smaller than the counterpoise length (d < L). Therefore,use Equation 5.14:

Substituting the values yields the following

As the length of the counterpoise increases, the ground resistance decreases. Forexample, if the counterpoise length is increased to 200 feet (60.96 m), then

Doubling the counterpoise length reduced the ground resistance by 44 percent.

where: ρ = 250 Ω-mL = 100 ft (0.3048 m/ft) = 30.48 md = 30 in. (0.0254 m/in.) = 0.76 ma = 1/2 (0.292 in.)(0.0254 m/in.) = 0.0037 m

R = In –1ρπL

2Lad

R = In –1 = 15.8Ω250Ω-m

π(30.48m)2 × 30.48m

(0.0037m)(0.76m)

R = In –1 = 8.8Ω250Ω-m

π(60.96m)2 × 60.96m

(0.0037m)(0.76m)

EXAMPLE 5.12: More Conductive Soil.

If the soil resistivity is 100 ohm-m instead of 250 ohm-m, a 100-foot counterpoise will have a groundresistance of:

This is a 60 percent reduction from 15.8 ohms (Ex-ample 5.11). Because soil resistivity and ground re-sistance are directly proportional, a 60 percentreduction in ρ produces a 60 percent reduction in R.

R = In –1= 6.3Ω100Ω-m

π(30.48m)2 × 30.48m

(0.0037m)(0.76m)

EXAMPLE 5.13: Counterpoise Burial Depth.

If the burial depth is increased to 60 inches (1.52 m) and the counterpoise length remains at 100 feet (30.48 m),then, using Equation 5.13,


Doubling the burial depth decreases the ground resistance by only 1.7 ohms, or about 11 percent.

where:ρ = 250 Ω-mL = 30.48 m

a = 0.0037 md = 1.52 m

R = In –2 + ρ2πL

2La+ In

Ld

– + 2dL

d2

L2d4

2L4

R = In –2 + 250Ω-m

2π(30.48m)2 × 30.48m0.0037m

+ In30.48m1.52

– + = 14.1Ω2 × 1.52m30.48m

(1.52m)2

(30.48m)2(1.52m)4

2 × (30.48m)4


Protecting underground distribution from light-ning surges originating on overhead lines is cru-cial. Analyzing the effect of transient voltagesand currents is one of the most complex subjectsin distribution engineering. Accurate solutions toovervoltage problems often require higher math-ematics and sophisticated computer simulations.The methods presented in this manual are ap-proximations and should be viewed as such.Most of the recommendations and protectivemeasures reviewed are based on complicatedanalyses. In most instances, only the results aregiven. For more information on why certain rec-ommendations were made, consult the refer-ences listed at the end of this manual.

OVERVIEWIn general, the equipment that must be pro-tected from lightning surges on an undergroundsystem is the same as on an overhead system:

• Transformers,• Switchgear, and• Cable insulation.

Installed cable is the most significant cost ofan underground system. Unfortunately, under-ground cable insulation is not self-restoring likeoverhead insulation because it is not surroundedby air. An underground cable fault is much moreexpensive to locate and repair than a fault on anoverhead line, which, most of the time, will becleared by a recloser operation. Limiting thenumber and severity of surge voltages will pro-long cable life. Therefore, it is important to pro-vide the proper surge protection.

Underground feeders consist of radial tapsfrom overhead distribution circuits. Normal prac-tice is for a cable run to have pad-mountedtransformers connected along its route. A typicalinstallation could be a short run of a few hun-dred feet or a long rural feeder terminated in anopen point, usually at a transformer. A lightningsurge traveling down the cable from the over-head line will double in magnitude at the openpoint as it reflects back on itself. As the reflectedsurge propagates back toward the riser pole, thedoubling effect is transferred throughout thelength of the cable. Because some underground

installations are protected only at the riser pole,the traveling wave phenomenon points out theproblem inherent in protecting undergroundequipment by locating arresters as close as pos-sible to the protected equipment.

Protection of underground systems servedfrom overhead lines is complex. The critical casegenerally involves lightning striking the linewithin one span of the riser pole. For high-cur-rent-magnitude, fast-front surges, the pole topwill flash over, diverting the surge current to thepole ground conductor, bypassing the arresterentirely. In theory, a riser pole arrester need op-erate only for low-magnitude, slow-wavefrontlightning currents left on the overhead line afteran insulator flashover (Parrish, 1982). But voltagedoubling plus reflections on the cable requires ariser pole arrester with the best available charac-teristics. Normally, a single arrester at the risercan keep voltages below the BIL withstand of12.47-kV cable and equipment. Dead-front ar-resters now available will reduce reflected surgevoltages by up to 50 percent. They should beused at 12.47 kV to reduce insulation voltagestress. However, 25-kV systems require open-point arresters, because equipment BIL does notdouble as the system voltage doubles, resultingin reduced protective margins. Historical outagedata at 25 kV has shown additional dead-frontarresters are justified at cable taps and additionaltransformer locations. (See Table 5.14 for recom-mended arrester ratings and locations.) Most co-operatives install open-point arresters on both12.47/7.2 kV and 24.94/14.4 kV.

Several sources of transient overvoltages ofsystem origin must be considered when surgearresters are applied. Overvoltages caused byneutral displacement during line-to-ground faultsand voltage regulation are addressed later in thissection. Overvoltages caused by ferroresonanceand possible solutions are presented in Section 6of this manual. Capacitor switching and current-limiting fuse operation are two other possiblesurge sources. These sources do not cause se-vere extra duty for arresters applied for under-ground lightning protection because of theirinfrequent occurrence. Shunt capacitors are notneeded on most cooperatives’ undergroundfeeders. Current-limiting fuses usually do not

5UndergroundSystem SurgeProtection

208 – Sect ion 5

cause harmful voltage levels because of circuitimpedances and the nonlinear magnetizing im-pedance of pad-mounted transformers. In addi-tion, both of these sources can be minimized byproper equipment selection.

Any discussion of lightning protection re-quires some knowledge of lightning phenomenaand its electrical characteristics. Volumes of liter-ature have been written on the subject sinceelectricity was harnessed for domestic use. Athorough review of the subject is beyond thescope of this manual. However, an NRECA pub-lication entitled Lightning Protection Manual forRural Electric Systems, NRECA Research Project92-12, by D.E. Parrish, offers an excellent start-ing point and an extensive bibliography for fur-ther reading.

5SURGE ARRESTER SELECTIONSurge Arrester TypesThe first device connected between line andground to protect power circuits from lightning-induced overvoltages was the simple air gap. Toprevent breaker operation every time the gapflashed over, the device had to be able to inter-rupt an arc at a current zero. This need led tothe development of the first expulsion arrester.Continued research to develop a better arresterthat would protect large power transformers ledto the gapped silicon carbide (SiC) valve arrester.Silicon carbide provided so many advantagesover previous designs that some pundits said nofurther improvements in the device were needed.

Researchers who continued testing SiC ar-resters found that, when hit with steep-frontwaves, gapped designs exhibited an undesirablecharacteristic. For waves with very fast rise times,a gap requires a considerably higher voltage tobreak down, which adds a sharp spike to theprotective characteristic. Solving this problem re-quired elimination of the gap, which was possi-ble with the discovery of metal oxide as a valvematerial. The result was the introduction of thegapless metal oxide varistor (MOV) surge ar-rester in the late 1970s. It was one of the mostsignificant advances in the history of overvoltageprotection, as proven by the wide acceptance ofmetal oxide technology by electric utilities sincethe mid-1980s. Manufacturers generally no longermake SiC arresters.

Metal oxide and SiC distribution arresters havesome similarities in construction (see Figure 5.35).The only real difference besides valve elementcomposition is the gap assembly in the SiC unit.Figure 5.35 also shows an externally gapped SiCarrester. The external gap will increase the ratedsparkover voltage of an arrester, but helps to re-duce outages caused by arrester failures. Whilethis was an important factor with silicon carbidearresters, the overvoltage protection benefits of notusing external gaps for riser pole applications faroutweighs any perceived outage rate reduction.

MOV designs are more efficient and offer bet-ter protective margins at the same voltage rat-ings. For these reasons, only MOV arresters willbe considered in later discussions of under-ground system surge protection.FIGURE 5.35: Types of Arresters and Their Construction.

Porcelain Insulator

Gasket seal

Compression Spring

Valve Element

Gap Assembly

Gasket & Seal

Line Connector

External Gap

Porcelain Housing

Ground Connector

Line Connector

Gasket Seal

Valve Elements

Porcelain Housing

Compression Spring

Ground Connector

Ground Lead Disconnector

Gap Assembly

Externally GappedSilicon Carbide Valve Arrester

GaplessMOV Arrester

Internally GappedSilicon Carbide Valve Arrester


Table 5.8 lists the maximum discharge voltagefor three MOV heavy-duty distribution class arresters for a 20-kA, 8 × 20 µsdischarge current wave. Thefirst two arresters are standardheavy-duty distribution classSiC and MOV arresters. Thethird is a special MOV arresterwith better characteristics de-veloped especially for riserpole applications.

Because increased protectivemargins can extend cable life and reduce equip-ment failures, external gaps should not be usedon MOV arresters for cable circuit protection.

5

FIGURE 5.36: Comparison of Nonlinear Characteristics of SiC and MOVValve Elements. Source: Kershaw, Gaibrois, and Stump, 1989.

Maximum Discharge Voltage for 8 x 20 µs Arrester Rating Discharge Current Wave (kV Peak)

kV rms HD SiC (20 kA) HD MOV (20 kA) RP MOV (20 kA)

9 40 34 27

10 45 37 29

18 81 68 53

21 94 79 62

*Characteristics shown are for Cooper Power Systems arrester types EL, AZL, and AZR400.Note. HD = Heavy Duty RP = Riser Pole

TABLE 5.8: Comparison of Protective Characteristics of Heavy-DutyDistribution Class Silicon Carbide, MOV, and Riser Pole MOV Arresters.*

Riser pole arresters represent a small percentageof the total arrester population on a system andshould not contribute significantly to extendedoutage times. Because most underground risersare fused ahead of the lightning arrester, failureof the ground lead disconnector to operateproperly will affect only the underground feeder.The overhead circuit will not suffer an outage ina properly coordinated system. The benefits ofnot using an external gap far outweigh any per-ceived reduction in quality of service that mightoccur.

Gapless MOV ArresterIn an MOV arrester, the valve elements are madefrom zinc oxide (ZnO). The valve elements ordisks are about 90 percent ZnO and are com-

bined with a variety of othermaterials to determine theelectrical characteristics of thevaristor. The ingredients arefirst mixed and then pressedinto disks at extremely highpressure. They are then firedin a kiln into a ceramic resistorwith a very nonlinear volt-am-pere characteristic.

The MOV valve elements are very nonlinear.The 60-Hz leakage current is in the low milli-am-pere range at normal line-to-ground voltage, whicheliminates the need for a series gap to insulate thearrester from ground. The sharp knee of the volt-ampere curve means that the disks go into con-duction at a precise voltage level and stop con-ducting when the voltage drops below that level.A series gap is, therefore, not needed to inter-rupt power follow current after a current surgepasses through the arrester. The MOV arrestereases out of conduction after the surge voltagepasses, without allowing hundreds of amperesof power follow current to flow, as does an SiCarrester. The MOV also eases into conductionwithout producing a sharp voltage spike at thestart of a lightning surge. This valve elementproperty represents a significant advantage overSiC technology in equipment overvoltage protec-tion. The nonlinear characteristics of SiC andMOV valve elements are compared in Figure5.36, which shows the extreme nonlinearity ofthe MOV (Kershaw, Gaibrois, and Stump, 1989).

MOV arresters have

better protective

characteristics than

do SiC arresters.

Silicon Carbide

Discharge Voltage

MOV

Normal Line-to-Neutral Voltage

< 0.1 Amp 100–500 Amps 1–100 kACurrent

Voltage

125ºC

75ºC

25ºC

Power Follow Current

Surge Current

Leakage Current

210 – Sect ion 5

A second MOV arrester quality that makes itbetter suited for cable protection is its protectivecharacteristic when subjected to current surgeswith fast rise times. A standard 8 × 20 µs currentwave is used to represent lightning in arrestertesting. It is considered by many experts muchtoo slow to accurately model a lightning surge.Fast wavefronts of one to three microseconds arenot uncommon for lightning strokes. The responseof an arrester to steep-front waves should beconsidered in the arrester selection process forcable protection.

Figure 5.37 illustrates the effects of fast rise timesurges for both MOV and SiC arresters as a mul-tiplier of the arrester discharge voltage (Niebuhr,1982). Inspection of the curves shows that theincrease in arrester discharge voltage understeep-front waves is more severe for SiC than forMOV arresters. Moreover, the sparkover charac-teristics of a gapped silicon carbide arrester willincrease for steep-front surges. Insulation protec-tion will be reduced accordingly. A gaplessMOV arrester will not exhibit this behavior.

Internally Gapped MOV ArrestersAs discussed in the previous subsection, tempo-rary overvoltages (TOV) are a primary concernwhen gapless MOV arresters are applied be-cause they cannot tolerate voltages above theMOV valve-on voltage for long periods. Twomanufacturers have taken different approachesto solve this problem. One uses a series resis-tance-graded gap structure and a reduced stackof MOV valve elements. The design provides in-creased TOV capability and improved protectivecharacteristics over gapless designs. The otheruses an increased number of disks for moreovervoltage capability. More valve elements re-duce the leakage current during expected tem-porary overvoltage conditions, thus preventingthermal runaway. Spark gaps are then used toshort the extra disks during a surge event andgive increased protective levels. Comparing thetwo gapped MOV arrester designs with a heavy-duty gapless design shows that a 20 percent re-duction in discharge voltage can be obtained.

Figure 5.38 shows a cutaway view of the twogapped arresters for riser pole applications andthe location of the gaps and disks.

5

FIGURE 5.37: Effect of Fast Rise Times on IR Discharge.

FIGURE 5.38: Series- and Shunt-Gapped MOV Distribution Arresters.

Silicon CarbideArrester

Metal Oxide VaristorArrester

0.10

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

1.0 10 100

Time (Microseconds)

Voltage (Per Unit)

MOV Discs

Insulated Terminal Cap

Shunt-Gap Module

Gap(s)

Spacer

Steel Coil SpringCoil Spring

Desiccant

IsolatorIsolator

Series-Gap Design Shunt-Gap Design

Series-Gap


According to the manufac-turers, the two differentgapped arresters provide thefollowing improvements overa gapless design:

• Lower discharge voltagecharacteristics,

• Higher temporary overvolt-age capability, and

• Increased thermal capacity.

Although these designs have been in the fieldfor some time, application engineers still have afew concerns about adding gaps to MOV arresters:

• Gap sparkover variability resulting from erosion,

• Contamination affecting sparkover level,• Changes in arrester characteristics with

time, and• Stability of internal seals and gaskets in the

presence of ozone caused by gap operationinside the housing.

5

FIGURE 5.39: Dead-Front Arrester Elbow Configuration.

Arrester engineers haveknown about these problemareas for years from experi-ence with SiC arresters andearly gapped MOV stationclass arresters. The presence of gaps should not prevent co-operatives from consideringtheir use to take advantage of

increased protective margins and better tempo-rary overvoltage capability offered by these de-signs for specific applications.

Dead-Front Lightning ArrestersDead-front arresters were developed to solve themajor problem inherent in the protection of UDcircuits: locating arresters as closely as possibleto the protected equipment. Various arrester de-signs and accessories provide convenient, eco-nomical, and reliable means to connect them toUD systems. Previously, gapped SiC arresterswere used in live-front applications in pad-mounted transformer enclosures with limitedsuccess. In addition to safety considerations required for live-front operation and the addedexpense of larger cabinets, the gapped arresterrelies on a spark-gap operation to protect theequipment. Gap operation is sensitive to groundplanes in enclosures; unless this effect is ad-dressed in the overall design of the protectionscheme, the arrester sparkover level will be affected. The advent of gapless MOV arresterseliminated the concern with gap operation andmade the development of dead-front arrestersfeasible for underground equipment protection.

MOV arresters for underground use are calleddead-front arresters because a semi-conductinggrounded shield is molded around the insulationand valve elements. Dead-front arresters havebeen in service for a number of years and theirconfigurations have been standardized for inter-changeability. Typical installations are in pad-mounted transformer enclosures, entry cabinets,vaults, and switching enclosures.

A cutaway view of a dead-front design matedto a load-break elbow connector is shown inFigure 5.39.

The electric utility industry uses three basicdead-front arrester configurations:

Consider gapped

MOV arresters

where temporary

overvoltages occur.

1. Metal oxide valve elements2. Semiconducting moulded shield3. Rubber insulation4. Probe5. Insert interface

6. Locking ring7. Operating eye8. Grounding eye9. Stainless steel end cap10. Ground lead

8

910

1

2

3

45 6

7

Features:

and reducing clutter within thetransformer.

Dead-front MOV arresterswith elbow connectors, bushingarresters, and parking standarresters are available frommanufacturers in all three volt-

age classes: 15, 25, and 35 kV. Figure 5.40 showsthe three types of dead-front arrester designs.

IEEE/ANSI C62.11, the IEEE Standard forMetal Oxide Surge Arresters for AC Power Cir-cuits, now covers the operating characteristics ofdead-front arresters. Dead-front arresters areclassified as light-duty arresters capable of pass-ing the following tests:

• 40-kA high-current withstand test;• 75-ampere, 2,000-µs low-current,

long-duration test; and• 5-kA duty cycle test.

The continuous ambient temperature require-ments are -40°C to 65°C, whereas the temporarymaximum arrester temperature is 85°C. For com-parison, ambient temperatures set by the stan-dard for overhead arresters are -40°C to 40°Ccontinuous and 65°C maximum. Thus, undernormal service conditions, underground arrestersmay operate at temperatures 25°C higher thanoverhead arresters. The higher operating temper-ature requirement is intended to address MOVarrester stability at high application temperaturesinside pad-mounted transformer enclosures.

Because metal oxide dead-front arresters areconsidered light-duty devices, they do not havethe same protective characteristics as heavy-dutyand specially designed arresters for riser poleprotection. Expected current magnitudes on un-derground circuits are not as severe as those onoverhead circuits because the riser pole arresteroperation reduces the surge magnitude on theprotected underground cables. Therefore, match-ing characteristics are not required, and under-ground arresters are designed with dischargevoltages approximately 20 to 40 percent higherthan arresters used for riser pole applications atthe same surge current magnitudes. Their dis-charge voltages are listed only for current surges

212 – Sect ion 5

1. Elbow Arrester. This is anMOV arrester used with aload-break elbow connec-tor. It is used mainly toconnect directly to a trans-former bushing. In otherapplications, it is used witha feed-through device or afeed-through insert.

2. Parking Stand Arrester. This is an arrestercombined with an insulated parking bushingfor mounting on a transformer or switchingenclosure parking stand. Typical use is atthe open-point transformer of a loop-feeddistribution circuit to park the disconnectedelbow connector. This arrangement helps re-duce transformer faceplate overcrowding.

3. Bushing Arrester. The bushing arrester con-figuration combines an MOV arrester with aload-break bushing insert for mounting direct-ly to the pad-mounted transformer bushingwell. It is used at the end of a radial circuitor at the open point of a loop. Surge protec-tion is provided while increasing operability

5Dead-front arresters

are applied close to

protected equipment.

FIGURE 5.40: Dead-Front Surge Arresters.

Dead-Front Elbow Arrester

Bushing Arrester Parking Stand Arrester


up to 20 kA versus 100 kA forsome heavy-duty designs.Table 5.9 lists typical ratingsand characteristics for dead-front arresters. The voltage rat-ings and maximum continuousoperating voltage (MCOV) arestandard values, whereas theprotective characteristics rep-resent industry values compiled from variousmanufacturers.

When dead-front arresters and riser pole ar-resters are applied on UD feeders, they are con-sidered to be in parallel when subjected to surgecurrents. Proper coordination is required to en-sure the larger riser pole arrester takes the bulkof the surge current so the discharge capacity ofthe lighter duty underground arrester is not ex-ceeded. Current sharing between the two de-vices depends on the discharge voltage of eacharrester when subjected to the same surge cur-rent and the total impedance between them.The total impedance is the cable surge imped-ance plus the ground leads of both arresters. Forproper current sharing, the dead-front arrestershould see between 10 and 20 percent of the

surge current carried by theriser pole arrester (Osterhout,1989). This condition can nor-mally be achieved by keepingthe riser pole ground leads asshort as possible and using ar-resters with the same voltagerating. If the riser pole leadsare substantially longer than

the normal three-foot elbow arrester lead, thedead-front arrester can be overloaded, especiallyfor fast-front incoming surges.

Arrester Performance ClassesThere are four basic classifications of lightningarresters:

1. Station,2. Intermediate,3. Distribution, and4. Secondary.

These classifications differ in voltage rating,thermal capacity, protective characteristics, stan-dard tests, and whether pressure relief is required.For the most part, the major difference between

5

Coordinate riser pole

and dead-front

arresters for proper

current sharing.

Duty Cycle Equivalent Voltage Rating MCOV Front-of-Wave Discharge Voltage (kV) **

(kV) (kV) (kV)* 1.5 kA 3 kA 5 kA 10 kA 20 kA

3 2.55 13.4 10.6 11.5 12.1 13.2 15.1

6 5.10 26.5 21.2 23.0 24.6 27.0 32.5

10 8.40 39.8 31.7 34.5 36.3 41.0 47.3

12 10.20 46.1 36.5 39.7 42.3 46.9 55.3

15 12.70 58.0 46.2 50.3 53.5 59.5 70.6

18 15.30 69.8 56.0 61.0 65.2 72.6 86.5

21 17.00 83.0 67.0 74.0 77.0 88.5 105.1

24 19.50 96.5 78.0 85.0 90.0 103.4 123.3

27 22.00 99.4 78.5 87.0 93.5 104.5 130.3

* Equivalent front-of-wave voltage is the expected discharge voltage of the arrester when tested with a 5-kA current surge peaking in 0.5 µs.

** Maximum discharge voltage for an 8/20 µs surge current.

TABLE 5.9: Typical Electrical Ratings and Characteristics of Dead-Front Surge Arresters.

214 – Sect ion 5

each arrester class is the physical size of the diskor block. A larger diameter block reduces IR dis-charge voltage and greatly increases energy ab-sorption capability and reliability. The properchoice of arrester class depends on the systemvoltage, protected equipment insulation level,and the size and cost of the equipment. The firstthree arrester classes can be used on a distribu-tion system because their voltage ratings over-lap. Distribution class arresters are usually usedon feeders, whereas intermediate and stationclass arresters are used in substations.

Because the various classes tend to overlap,the easiest way to distinguish among them is toknow the different standard tests performed foreach class. Table 5.10 lists the tests required byANSI/IEEE Standards C62.1 and C62.11.

For the protection of underground circuits atriser poles, MOV heavy-duty distribution classarresters are normally used. The greater currentdischarge requirements of the HD designationinherently mean these arresters will have a lower

5Arrester Class

Characteristic Distribution Intermediate Stationor Feature (1-30 kV) (3-120 kV) (3-684 kV)

Approximate Protective 3.5 pu 3.0 pu 2.7 puCharacteristics (at 10 kA)*

Current Discharge Requirements

High Current, Short Duration 65 kA (ND) 65 kA 65 kA100 kA (HD)

Duty Cycle 22-5 kA (ND) 5 kA 10 kA (>550 kV)20-10 kA & 2-40 kA 50 kA (550 kV)(HD) 20 kA (800 kV)

Low Current, Long Duration 20-75 A (ND) Transmission Line Discharge 20-250 A (HD) Test Required

Pressure Relief

High Current Not Required 16.1 kA 40–65 kA

Low Current Not Required 400–600 A 400–600 A

* In pu of arrester ratingNote. ND = Normal duty; HD = Heavy duty

TABLE 5.10: Comparison of Standard Requirements for Surge ArresterClassifications.

discharge characteristic than a normal-duty distri-bution class arrester. Various manufacturers havedeveloped what is called within the industry a“riser pole” class of arrester. This class is not rec-ognized by standards. To obtain better protectivecharacteristics, the manufacturers have essential-ly taken intermediate class blocks and packagedthem in different housings. In short, taking blockswith better characteristics and placing them indistribution class housings of porcelain or polymerconstruction results in better protective characteris-tics at a reduced cost. The distribution classhousing surrenders the pressure-relief capabilityof intermediate class units, but their electricalcharacteristics are kept. The units are also mucheasier to mount on distribution crossarm struc-tures. These arresters should be strongly consid-ered for any underground application becausethey provide better protective margins.

SURGE ARRESTER APPLICATION FACTORSVoltage RatingThe voltage rating of an MOV arrester is basedon its operating duty-cycle test. The duty-cycletest defines the maximum permissible voltagethat can be applied to the arrester and still haveit discharge its rated current. For an MOV ar-rester to be applied, the voltage rating must beabove the maximum expected line-to-groundvoltage at which the arrester will have to dis-charge a current surge. Under most conditions,the maximum voltage will occur on the un-faulted phases of a three-phase circuit during asingle-line-to-ground fault.

The explanation above alludes to an impor-tant quality of metal oxide arresters. Because ofthe thermal properties of metal oxide, they candissipate current surges at higher system volt-ages than would be seen under normal operat-ing conditions. Figure 5.36 shows that the ZnOcurrent characteristic will shift to the right withincreasing temperature. The shift also producesincreased leakage current. The material will re-main stable as long as a surge event does not in-crease the temperature to a point where increas-ing leakage current causes thermal runaway(Kershaw, Gaibrois, and Stump, 1989).

Increasing normal line-to-neutral voltage abovethe knee of the leakage-current characteristic


5across the arrester during nor-mal service. For arresters oneffectively grounded systems,the MCOV is based on thenominal system line-to-neutralvoltage, plus a continuousovervoltage operating factor.For well-regulated systems, this

factor is often considered to be five percent. How -ever, the engineer selecting MOV arresters shouldreview the system operating characteristics to de-termine the applicable factor. The MCOV require-ment would be 7.56 kV for a 12.47-kV nominalsystem voltage (1.05 × 12.47 kV ÷ 3) undermost conditions. A more thorough discussion ofMOV arrester voltage rating selection is given inthe next subsection, Line-to-Ground Faults.

The standard voltage rating and MCOV for alldistribution class arresters are shown in Table 5.11.

Another consideration in the application ofMOV arresters is temporary overvoltages, suchas the single-line-to-ground fault mentioned pre-viously. A metal oxide arrester will operate suc-cessfully as long as it is not required to dissipatemore than its design energy level. Operatingtime above arrester voltage rating is set by theamount of energy the arrester must dissipateduring the event. If the overvoltage on the ar-rester is reduced to its MCOV before it gets toohot, thermal runaway will not occur and the ar-rester will not fail.

Temporary overvoltage capability curves arepublished by each manufacturer for its products.Typical overvoltage curves are shown in Figure5.41. Similar curves should be considered whenan arrester is subjected to system overvoltageconditions.

Two system conditions that can affect thevoltage rating selected for a riser pole MOV arrester application are overvoltages caused by:

• Line-to-ground faults, and• Voltage regulation.

Line-to-Ground FaultsSelecting the proper MOV arrester voltage ratingis based on experience and on calculated over-voltage values for the unfaulted phases of three-phase circuits during a single-line-to-ground

curve for a sustained periodwill also cause thermal run-away. For this reason, the se-lection of an MOV arrester isbased on the MCOV applied

An MOV arrester

rating is set by its

MCOV.

FIGURE 5.41: Temporary 60-Hz Overvoltage Capability Curves—Typical MOV Distribution Arrester.

Duty-Cycle Voltage MCOV

3 2.55

6 5.10

9 7.65

10 8.40

12 10.20

15 12.70

18 15.30

21 17.00

24 19.50

27 22.00

30 24.40

TABLE 5.11: Metal Oxide Surge ArresterRatings in (kV) Root Mean Square. Source:ANSI/IEEE C62.11-1987.

0.1 1.0 10

60ºC Ambient

Permissible Duration (Seconds)

60-Hz Voltage—Per Unit Arrester Rating

100 1,0000.80

0.90

1.00

1.10

1.20

1.30

1.40

1.50

No Prior Duty

Prior Duty

216 – Sect ion 5

fault. The most common application rule foropen-wire, four-wire wye, effectively groundedsystems is shown in Equation 5.16.

The Range A factor is 1.05 when voltage lim-its are as follows:

• Minimum service voltage =114 Volts, and

• Maximum service voltage =126 Volts.

The equivalent primary volt-age values are as follows:

• Minimum service voltage = 6,840 Volts, and• Maximum service voltage = 7,560 Volts.

The 1.2 in Equation 5.16 represents a safetyfactor of 20 percent. Equation 5.16 representsthe maximum voltage rise on the unfaultedphases of a loaded circuit. The voltage rating isthen equivalent to 1.25 times the nominal line-to-neutral system voltage. The calculation for a12.47-kV system is 7,200 × 1.25 = 9 kV.

This application rule is very conservative forSiC arresters. The maximum calculated voltage isequal to the arrester rating, and arrester spark -over far exceeds the rating. For an SiC arresterto operate, a transient voltage surge will have tooccur while the 60 Hz overvoltage due to neu-tral shift exists.

The same rule is not as conservative for metaloxide arresters unless it is known that the sys-tem is truly effectively grounded. For riser poleapplications with BCN cable, effective ground-ing can be assumed with a reasonable degree ofaccuracy. With the installation of jacketed cable,effective grounding might not be achieved. Anaccurate estimate of the voltage on the unfaultedphases can be calculated by factoring in groundwire size, ground rod spacing, fault resistance,earth resistivity, and system impedance. The calcu-lated overvoltage is then compared with the MOVarrester temporary overvoltage curves. When in

5Equation 5.16

Arrester Rating ≥ (Line-to-neutral voltage) × (Range A factor 1.05 × 1.2)

doubt, some cooperatives are now using a factorof 1.35 instead of 1.25, which would lead to theselection of the next higher arrester duty-cyclevoltage rating at 12.47 and 25 kV (10 kV and 21 kVrather than 9 kV and 18 kV).

Voltage RegulationRUS Bulletin 1724D-112, The Application of Ca-pacitors on Rural Electric Systems, calls for maxi-mum service voltages to be no greater than five

percent above nominal forRange A voltage limits. Thebulletin does not limit voltagefluctuations on feeders. Capac-itor operation at light loads,lightly loaded undergroundprimary cables, or voltage reg-ulator malfunction can lead tosystem voltages up to 10 per-cent above nominal without

the cooperative’s immediate knowledge. A 10percent voltage increase on a 12.47-kV feederwith a 9-kV riser pole arrester would lead toabout a four percent MCOV overvoltage on thearrester (120 × 1.1 × 60 ÷ 7.65 kV = 1.035 pu ofMCOV rating). The problem is that these feederovervoltages may be present for hours, not sec-onds. The long-term stability of metal oxidevalve elements has been proven at the MCOV,not at these possible higher voltages. Prior dutyon the arrester will also increase thermal aging.

Range A voltage levels must not be exceededon feeders if 9- and 18-kV MOV arresters are in-stalled on the system. If higher voltages are knownto occur for sustained periods, the next higherarrester duty-cycle voltage rating should be used(10 kV and 21 kV).

Protective MarginThe level of protection provided by an arrester iscalled the protective margin. It can be defined asthe percentage that insulation strength exceedsthe maximum surge voltage allowed by thesurge arrester and its leads. Insulation strength iscommonly referred to as the BIL, which is basedon the industry standard lightning voltage wave-shape of 1.2 × 50 µs. The standard lightning cur-rent waveshape is an “8 × 20” wave, meaningthat its rise time to peak is 8 µs with a time-to-half value of 20 µs. Figure 5.42 shows the current

Pick the next higher

arrester rating

when unsure about

overvoltage duration.


waveform. This test wave is used to establishcomparative IR discharge voltage data shown incatalogs of arrester characteristics. For example,a heavy-duty MOV riser pole arrester with a 9-kVrating might have a maximum discharge voltageof 24.5 kV when impulsed with a 10-kA, 8 × 20 µscurrent wave. This current wave produces approximately a 10-kA/8 µs = 1.25 kA/µs average

5

FIGURE 5.42: Typical Test Current Waveshape: Sinusoidal Wavefront.

0µs 10µs 20µs

Time

I/2I

100µs

Current (kA)

rise time, which is much slower than a typicalstroke discharged by an arrester. As noted earlierin this section, the change in current magnitudewith time is sometimes expressed as di/dt.

To calculate protective margin, add the L di/dtinductive voltage drop in the arrester leads carry-ing surge current to the arrester discharge voltage.The inductance of solid wire used for connec-tions is a constant and is typically assumed to be0.4 microhenries per foot (µH/ft). Research datahave shown that the average rise time for a typi-cal lightning stroke, which is defined as the rateof current increase per microsecond, is closer to4 kA/µs than the 1.25 kA/µs value mentionedabove. Using a di/dt of 4.0 kA/µs gives a voltageof 4.0 × (0.4) = 1.6 kV/ft of lead, which must beadded to the discharge voltage to calculate thetotal protective margin. For more information onthis subject, see the IEEE guide on arrester leadlength calculations.

The protective margin for a cable installationmay be calculated using the following basic for-mula in Equation 5.17.

Comparing the above margin with the 20 per-cent recommended industry standard shows theinstallation is more than adequately protected.After other elements are considered, it will beshown that the above level of protection is opti-mistic in most cases.

Rate of RiseThe standard 8 × 20 µs current waveshape usedfor testing was intended to represent a typicallightning stroke. Recent field tests and recordeddata show much greater variation than that rep-resented by the standard. Surge current risetimes vary with each lightning discharge. Ac-cording to recent data compiled on electrical pa-rameters of lightning return strokes, typical risetimes can vary anywhere from 0.1 to 30 µs withcurrent magnitudes greater than 110 kA. Proba-bility data from recorded lightning strokes areshown in Figure 5.43 and are more representa-tive than the 8 × 20 µs wave. Researchers havereported rise times higher than 10 kA/µs for morethan 50 percent of stroke currents. Maximum riserates greater than 75 kA/µs have been recorded.

Standards recognize that some fast-front surgeconditions produce current waves peaking inless than eight microseconds. For surges that

Equation 5.17

where: BIL= Equipment BIL, in kVIR = Arrester discharge voltage, in kVLV = Lead voltage, in kV

PM(%) = –1 BIL

IR + LV× 100

EXAMPLE 5.14: Protective Margin Calculation for Riser PoleApplication: Industry Standard 4 kA/µs Average Rise Time forLightning Strokes Assumed.

PM(%) = –1 95

26.5 + 2(16)× 100

PM(%) = [3.20 –1] × 100

PM = 220%

Assume a 12.47-kV riser pole installationis protected by a 10-kV MOV arresterconnected with a two-foot lead. ArresterIR discharge voltage for a 10-kA, 8 × 20current surge is 26.5 kV. A lead voltageof 1.6 kV/ft will be assumed. EquipmentBIL is 95 kV.

218 – Sect ion 5

peak in two microseconds orless, the insulation strength isthe Chopped Wave Withstand(CWW). For oil-filled equip-ment, including pad-mountedtransformers, the CWW is 15percent higher than the BIL.The insulation strength ofcable, unlike oil-filled equip-ment, does not increase as therise time of the applied surgevoltage decreases. For the purpose of insulationcoordination, the CWW of a cable is consideredequal to its BIL for all surge voltage waveshapes.

For the comparison of various arrester charac-teristics under these conditions, an EquivalentFront-of-Wave (FOW) protective level was derivedspecifically for gapless MOV arresters. It denotesthe fact that a surge current with a faster rise timeto peak than the standard 8 × 20 µs test wave willproduce a higher discharge voltage in an MOVarrester. This increased voltage is more severe forSiC arresters. For example, referring to Figure5.37, assume a time-to-peak of one microsecond.The curves show that the IR characteristic of anSiC arrester increases approximately 30 percent,while the MOV increase is about 10 percent.

The equivalent FOW characteristic for anMOV arrester is the arrester discharge voltagefor current pulses having a time-to-peak ofabout 0.6 µs. This current waveshape produces

5

FIGURE 5.43: Lightning Rise Time to Peak.

1 2 3 4 5 6 7 8 9100

80

60

40

20

0

17%Percentage Probability That Time toPeak Will Equal or Be Less Thanthe Time Shown on the X Axis

Percentage Probability

Time to Peak (Microseconds)

57%

a voltage wave across the arrester peaking in 0.5µs. The resulting peak voltage is the value listedin tables of arrester characteristics. The questionof what rate of rise to use with the equivalentFOW characteristic is still an open debate amongprotection engineers. The consensus has nar-rowed the rate down to between 10 and 20kA/µs, depending on experience and the fre-quency of lightning in the area. Multiplying by0.4 µH/ft gives a lead wire voltage drop of between four and eight kilovolts per foot.

Because FOW characteristics for MOV arresters are higher than standard discharge voltages, and high rate-of-rise surges producegreater voltages per foot of lead, fast-front surgeconditions put maximum stress on cable insula-tion. When protective margins are calculated,

some application engineersrecommend that FOW pro tective levels for MOV arresters be used along with lead length voltage of six kilovolts per foot.

Lead LengthDischarge voltages from surgearresters travel through a cableat half the speed of light.When a traveling wave

reaches a point of high impedance such as anopen point on a loop, it reflects on itself. Thisreflection doubles the voltage at the open pointand along the cable as the incoming and re-flected waves overlap. Voltage doubling on thecable system must be considered when protec-tive margins of arrester installations are calcu-lated. To minimize the surge voltage entering acable, install an arrester with low discharge char-acteristics at the riser pole, connected with theshortest leads possible.

Tables 5.12 and 5.13 compare protective mar-gins on 24.9- and 12.47-kV systems using threedifferent arrester types. The BIL margin percent-ages are calculated using the industry standard10-kA, 8 × 20 µs waveshape, which is assumedto produce 1.6-kV/ft inductive voltage drop inthe series arrester leads. The CWW insulationwithstand is based on a 10-kA surge currentthat produces a discharge voltage that peaks in

For fast-front waves,

use the FOW

characteristic to

calculate protective

margin.


0.5 µs. This type of wave produces the dischargevoltages with kV peaks shown in the ArresterData FOW columns. A rise time of 15 kA/µs willbe assumed to produce a six-kilovolt per footvoltage drop in the leads to represent severefast-front lightning strokes. The IR discharge andlead length voltages are added and then multi-plied by two to represent the voltage doublingeffect caused by reflections.

Inspecting the tables shows that, for the stan-dard 8 × 20 µs waveshape and three-foot leads,the 12.47-kV system has 20 percent or bettermargins. Only the special riser pole MOV canprovide this level of protection on the 24.9-kVsystem. For fast-front surges, the protective mar-gins drop drastically when lead length effects areincluded. In the 24.9-kV system, eliminating thearrester lead length entirely results in a 20 per-cent margin for the riser pole MOV. The otherarresters provide no protective margin whenlead effects are considered. To provide the great-est protective margins for underground cables,keep the arrester discharge path (lead length) asshort as possible in all installations.

Arrester lead length is the combined line andground lead length in series with the arresterand in parallel with the cable’s termination. Figure 5.44 shows an installation that corre-sponds to the three-foot-lead examples in Tables 5.12 and 5.13.

5

FIGURE 5.44: Arrester Lead Length Equal to Three Feet.

Arrester Data Protective Margin (%)*

10 kA IR (kV Peak) Zero Lead Length 1.5-Foot Lead 3-Foot Lead

Arrester Type 8 × 20 FOW** 8 × 20 FOW** 8 × 20 FOW** 8 × 20 FOW**

Heavy-Duty SiC 69 80 -9 -22 -12 -30 -15 -36

Heavy-Duty MOV 60 66 4 5 0 -17 -4 -26

Riser Pole MOV 48 52 30 20 24 2 18 -11

LV = lead voltage = feet × 6 kV/ft for FOW LPL = Lightning Protective LevelLV = lead voltage = feet × 1.6 kV/ft for 8 × 20 LPL = FOW or 8 × 20 for 10-kA IR (kV Peak)

**Based on 10-kA current impulse that results in a discharge voltage peaking in 0.5 µs

TABLE 5.12: Protective Margin, 24.9-kV Underground Distribution System: 125-kV BIL Insulation,18-kV Arresters at Riser Pole Only, 10-kA Lightning Discharge, Surge Voltage Doubled byReflection.

*Protective Margin (%) = –1 BIL

2 × (LPL + LV)× 100

JCN CableLead = 18”

Lead = 18”

Lightning Arrester

220 – Sect ion 5

5

Remember, keep lead

length short to

increase protective

margin.

Arrester Data Protective Margin (%)*

10 kA IR (kV Peak) Zero Lead Length 1.5-Foot Lead 3-Foot Lead

Arrester Type 8 × 20 FOW** 8 × 20 FOW** 8 × 20 FOW** 8 × 20 FOW**

Heavy-Duty SiC 35.0 42 36 10 27 -9 20 -22

Heavy-Duty MOV 30.0 33 58 44 47 13 36 -7

Riser Pole MOV 24.5 27 94 76 77 32 62 6

LV = lead voltage = feet × 6 kV/ft for FOW LPL = Lightning Protective LevelLV = lead voltage = feet × 1.6 kV/ft for 8 × 20 LPL = FOW or 8 × 20 for 10-kA IR (kV Peak)

**Based on 10-kA current impulse that results in a discharge voltage peaking in 0.5 µs

TABLE 5.13: Protective Margin, 12.47-kV Underground Distribution System: 95-kV BIL Insulation,9-kV Arresters at Riser Pole Only, 10-kA Lightning Discharge, Surge Voltage Doubled byReflection.

*Protective Margin (%) = –1 BIL

2 × (LPL + LV)× 100

Figure 5.45 shows a similar installation exceptthe line connection is taken to the arrester andthen to the termination. All arrester line lead iseliminated because the wire carrying surge cur-rent through the arrester is not in parallel withthe termination.

Figure 5.46 shows how arrester lead length canbe virtually eliminated by modifying the installa-tion of Figure 5.45. The arrester is mounted be-tween the termination and the pole ground con-ductor, so the pole ground conductor can be car-ried directly to the base of the arrester. The con-nection makes the arrester ground lead lengthzero with respect to the concentric neutral of thejacketed cable. Because no surge current flowsin either line or ground leads, the surge voltageacross the termination is limited to the dischargevoltage of the arrester and represents the “zerolead length” examples in the tables.

The easiest way to remember how to makethe best connections can be summarized as fol-

FIGURE 5.45: Arrester Lead Length Equal to 1.5 Feet.

Lead = 18”

Lead = 0”

Cable Termination


5

FIGURE 5.46: Zero Arrester Lead Length.

Lead = 0”

Lead = 0”

Cable Termination

Equation 5.18

where: L = Inductance, in Henries per unit lengthC0 = Capacitance, in Farads per unit length in free space

V = ≈ 3 × 1010 cm/second = 984 ft/microsecond1LC0

Equation 5.19

where: k = Insulation dielectric constant (typical values from 2 to 4)

V = = ft/microsecond≈ 1LC

3 × 1010 cm/secondk

984k

Connect to the

arrester first, then to

the cable, to minimize

lead length.

lows. Carry the line and ground connections tothe arrester terminals first, and then to the con-ductor and ground terminals of the cable termi-nation. This procedure will ensure the leads arekept as short as physically possible to make fulluse of the protective margin provided by riserpole arresters (Hubbell/Ohio Brass Co., Hi-Ten-sion News, 1989).

The engineer must recognize the extreme im-portance of arrester lead arrangement on effectiveovervoltage protection for underground systems.Furthermore, the engineer must communicatethis importance to installation crews, who havefinal control over this item. Improper arresterlead arrangement can cancel the advantages ofeven the most advanced arresters and lead topremature failures on underground systems.

TRAVELING WAVES ON UNDERGROUNDDISTRIBUTION SYSTEMSA lightning stroke to an overhead line will causea transient condition to occur. This rapid voltagebuildup caused by the discharge of energy froma charged cloud is not transferred instantaneous-ly to all points on the overhead line or connect-ed cable. In fact, the surge requires a finite timeto propagate down the line. The surge movementis in the form of a traveling wave. The travelingwave characteristics are determined by the dis-tributed nature of the capacitance and inductanceof the line. Its propagation speed is also set byline characteristics.

For overhead lines, the velocity of wave propa-gation, V, is calculated as shown in Equation 5.18.

The calculated value of 984 feet/µs is approxi-mately the speed of light. For overhead lines inopen air, the line conductor acts only as a guidefor the electromagnetic disturbance and the ve-locity of propagation is near the speed of light.

222 – Sect ion 5

For underground cables, theelectromagnetic wave does nottravel through air, but throughthe cable insulation. The ve-locity in this instance dependson the L and C of the cable,which are determined by itsinsulation material and physi-cal dimensions. Equation 5.19shows the calculation for the velocity of thewave in a cable with a dielectric constant of “k.”The capacitance of the cable is increased in pro-portion to the dielectric constant of the insula-tion. Therefore, the velocity in cable is where kis the dielectric constant of the cable insulation.

5

Therefore, the velocity in cable is

where k is the dielectric constant of the cable insulation.

V = 1LkC0

Two types of cable insulation—TR-XLPE andEPR—are normally used by cooperatives for un-derground applications. The approximate dielectricconstants for these two insulation materials aretypically 2.3 and 3.0, respectively. If 984 ft/µs isassumed to be the speed of light, surge propaga-tion speeds within the two cables are as follows:

TR-XLPE: V = 649 ft/µsEPR: V = 568 ft/µs

Figure 5.47 is the classicrepresentation of a transmis-sion or distribution line withdistributed L and C parame-ters. Also depicted in the fig-ure is the current I, whichrepresents the charging cur-rent produced by the voltagesurge as it travels along the

line. The current waveshape is the same as thevoltage, and these parameters are related by thesurge impedance of the line:

Surges travel at

approximately half

the speed of light

in cables.

FIGURE 5.47: Representation of Distributed Parameter Distribution Line.

L L L L

C C C C C

I I I

Voltage Surge

V

For overhead lines:ZSURGE = Surge impedance

= 500 ohms (400- to 600-ohm range)

For underground cables:ZSURGE = 35 ohms (20- to 60-ohm range)

The line charging current should not be con-fused with lightning surge current, which will notflow until a discharge path to ground is formed.

Once a traveling wave is initiated, it will con-tinue along a line until its energy is dissipated or until a change in surge impedance occurs.Changes in surge impedance that are importantfor cable protection occur at overhead/under-ground connections (riser poles), open cableend points, and midpoint cable taps. The magni-tude of the traveling voltage and current wavesis changed at the junction points. Waves dividein proportion to the equivalent surge impedanceat the junction according to Kirchhoff’s laws.This division gives rise to reflected and refracted(continuing) portions of the incident wave.

Equations 5.20 and 5.21 may be used to calculate the traveling wave voltages and cur-rents where a line terminates on an equivalentsurge impedance. Figure 5.48 shows the effect of a traveling voltage wave meeting a change insurge impedance at a junction. After the incidentwave encounters the discontinuity, three compo-nents of the wave exist:

V = 1LC

ZSURGE = LC

I = V

ZSURGEZSURGE =

LC


1. Incident wave (V1),2. Refracted wave (V2), and3. Reflected wave (V3).

Traveling voltage waves are illustrated in Fig-ure 5.49. The (a) view of Figure 5.49 shows a

traveling wave (in rectangular form for simplicity)approaching a junction point (JP) on impedancepath Z1. Various surge impedance conditions be-yond point JP are shown in the other four views(Kershaw, 1970).

5

FIGURE 5.48: Change in Surge Impedance at a Junction Point—Effect on Traveling Voltage Wave.

Junction Point(JP)

Incident V1

Reflected V3

Z1 Z2

V2 = V1 + V3I2 =I1 + I3

I1 = V1 /Z1I2 = V2 /Z2I3 = –V3/ Z1

V1 /Z1 – V3 /Z1 = V2 /Z2V1 /Z1 – V3 /Z1 = (V1 + V3) /Z2

Refracted V2

Equation 5.20

The Reflection Coefficient (K)V3 /V1 = (Z2 – Z1)/(Z2 + Z1) = K

Equation 5.21

The Refraction Coefficient is Then:V2 /V1 = 2Z2 /(Z1 + Z2) = 1 + K

Where: V1, I1 = Incident Voltage and Current Approaching Junction PointV2, I2 = Refracted Voltage and Current Continuing Beyond the Junction PointV3, I3 = Reflected Voltage and Current from the Junction Point

Z2 = Equivalent Surge Impedance Beyond the Junction Point(Z2 = Parallel Impedance at all Lines Connected to the Right of the Junction Point)

Z1 = Equivalent Surge Impedance to Incident and Reflected Waves

224 – Sect ion 5

Cable Open-End Point Terminated by NonlinearResistance (Gapless MOV Arrester)Until now in the discussion of wave behavior ata junction point, only differences in surge imped-ance magnitude have been considered. An MOV

arrester response at an open point presents aninteresting case because it is a nonlinear resis-tance. The incident voltage wave starts to dou-ble as previously described for an open pointuntil the MOV valve elements start to conduct

5

FIGURE 5.49: Traveling Wave Behavior at Junction Points Terminated with Various Surge Impedances.

V1

V1V1 = V2

V2

Voltages Cancelat a Short Circuit

I = 0 at All Timesat an Open point

V1

V3

V3

V1

(a)Traveling Wave V1 Incident on Junction Point (JP) on Impedance Path Z1

(b) Z1 = Z2, All of the Voltage Is Refracted

(c) Z2 = 0 Represents a Ground or Short Circuit

(e) Z2 = 0.1Z1 Represents an Overhead Line Dead-Ending at a Riser Pole

(d) Z2 = ∞ Represents an Open Circuit

Z2Z1

Z2Z1

Z2Z1

Z2Z1

JP

JP

Z2 Representsequivalent surgeimpedance beyond junction point

May also be assumed to model the response at an end-of-line transformer. Transformer HV windings represent a small capacitance at transient frequencies. Voltage doubling still occurs; however, the reflected wave front would have a different shape.

V1

V1

V3

V3

V2

V2Z2Z1

Shows Progression of Waveforms:Incident (V1), Refracted (V2), Reflected (V3)

Equation 5.22

Equation 5.23

In this case a voltage wave of 18% of the incident value continues onthe cable, while 82% of the wave is reflected back toward the source,cancelling a like portion of the incident wave.

V2 = V1

V2 = 0.182 V1

= V12Z2

Z1 + Z2

2(0.1)1.1

V3 = V1

V3 = –0.818 V1

= V1Z2 – Z1Z2 + Z1

0.1Z1 – Z10.1Z1 + Z1


toward the source superimposed on the incom-ing wave, V1 (Cooper Power Systems, 1990).

The preceding analysis shows that an MOVarrester at a cable open-end point will preventvoltage doubling and transfer of the overvoltageto the sending end of the cable by reflections.Voltage doubling does not occur, but the re-flected voltage is increased by one-half thevalve-on voltage of the arrester. The percentageof voltage increase over the limited riser polelet-through voltage depends on the IR character-istics of the two arresters.

PROTECTION METHODS ARRESTER LOCATIONSThe decision of where to place arresters on un-derground systems for equipment protection isbased on how the cable is configured and howits conductor is terminated. The previous subsec-tion on traveling waves showed that a change insurge impedance, whether caused by tapping acable or an open point, would cause reflections.The equivalent surge impedance at the disconti-nuity sets the magnitude of the reflected wave.At an open point, the voltage doubles back to-ward the source, subjecting the entire cablelength to the overvoltage. If the cable has one ormore open-ended lateral taps, the reflectedwaves added together can produce more thantwice the riser pole let-through voltage. Properlocation of dead-front or elbow surge arresterswill offer increased protective margins at allpoints within the underground system. Engineersshould consider using them even on 15-kV sys-tems to reduce overvoltage magnitudes and pro-long cable life.

The engineer cannot calculate protective lev-els at each piece of underground equipmentwithout transient analysis software, but generalrules will produce adequate protection for mostcommonly encountered situations. To provide anidea of the effectiveness of various protectionschemes without doing sophisticated travelingwave analyses, this subsection will evaluate sev-eral schemes that utilities use. The effectivenessof the schemes will be determined by comparingtheir protective levels at various locations to thelevel provided by a single riser pole arrester.

The following seven overvoltage protectionschemes will be considered:

5

FIGURE 5.50: Traveling Waves at a Cable Open-End Point Terminatedby an MOV Arrester.

(Figure 5.50). At this point, the excess voltage isshort-circuited to ground through the arrester. Itis also assumed the IR discharge voltage equalsthe valve-on voltage and remains constant through-out the surge event. The reflected wave, V3, ispositive and adds to the incoming wave, V, untilthe arrester starts to conduct. Voltage at thejunction point is then canceled as the negativeportion of the wave is reflected upon the incom-ing wave. However, before wave cancellationstarts, it is preceded by the positive reflectedportion of the wave, which adds to the incom-ing wave. The positive reflection adds aboutone-half the valve-on voltage to the incomingwave. The peak voltage, VT, then travels back

V1

V1

V1

VT

Valve-OnVoltage

Valve-OnVoltage

Valve-OnVoltage

Incoming WaveBefore Valve-On

At Valve-On

After Valve-On

Peak Voltage = VT = V2 + V1 Peak

VT

V2

V2

V1

VT

V2

226 – Sect ion 5

1. Riser pole arrester;2. Riser pole arrester and cable-end arrester;3. Riser pole, cable-end, and an arrester

applied at the first transformer on the sourceside of the open point (third arrester);

4. Riser pole arrester protecting a cable with alateral tap;

5. Lateral tapped cable with riser pole andopen-end arresters;

6. Lateral tapped cable with riser pole, open-end arresters, and an arrester at the tappoint; and

7. Riser pole arrester and under-oil arresters atevery transformer.

The seven protection schemes are shown inFigure 5.51.

Riser Pole Arrester Only (Figure 5.51, No. 1)For 15-kV class systems and below, a single arrester at the riser pole will generally provide adequate protective margins for cable-connectedequipment. As system voltages increase to25 kV, equipment insulation levels, unfortu-nately, do not double as well. For 25-kV systemswith 125-kV BIL using 18- or 21-kV arresters, theprotective margins for a riser-pole-only arrange-ment can be nonexistent. In this case, arrestersmust be added to the open-end points.

The maximum voltage stress that the entirecable and connected equipment can be roughlycalculated using Equation 5.24, which shows thedoubling effect.

Equation 5.24 shows that, if care is taken toreduce arrester lead length, the major contribut-ing factor to cable voltage stress is the doublingof the riser pole discharge voltage. Using a SiC

5

Equation 5.24

VC = 2(VRP + VL)

where: VC = Maximum cable and equipmentsurge voltage, in kV

VRP= Riser pole arrester discharge voltage,in kV

VL = Lead voltage drop, in kV

Equation 5.25

where: VC =Maximum cable and equipmentsurge voltage, in kV


VL = Lead voltage drop, in kVVOP= Open point arrester discharge

voltage, in kV

VC = VRP + VL + VOP12

heavy-duty arrester on a 7.2/12.5-kV systemcould lead to cable voltages extremely close tonew 15-kV equipment strength (95-kV BIL).Using a specially designed riser pole MOV arrester instead of an SiC design should reducemaximum cable surge voltage (VC) by 40 to 60percent. A reduction of this amount is importantwhen aged insulation is considered or whenfast-front surge currents enter the system.

Riser Pole and Cable-End Arrester (Figure 5.51, No. 2)Placing an arrester at the open point terminatesthe cable with a low impedance when the ar-rester conducts. The low arrester impedancegenerates a negative reflected wave that worksto reduce the voltage at the open point andalong the entire cable length. The maximum system surge voltage is given by Equation 5.25.

Figure 5.50 shows that maximum voltages willalways occur away from the cable-end arrester.The dead-front arrester eliminates cable-endvoltage doubling and limits the open-point volt-age to its protective level. The reflected voltage(VT) appears as a triangular spike that is super-imposed on the incident voltage wave and trav-els back toward the riser pole. The peak of thespike is approximately equal to 50 percent of thedead-front arrester discharge voltage at a currentlevel of 1.5 kA.

As the spike returns to the riser pole, it subjectsmost of the cable run to surge voltages that ex-ceed the protective levels of the arresters at eitherend of the cable. However, the overvoltages areless than the doubling of the riser pole arrester


51. Single-Phase UD Feeder

JacketedNeutral

CableNeutral

Riser Pole Arrester Only

OpenPoint

4. Single-Phase Feeder with Lateral Tap

TapPoint

Lateral Tapped Cable with Riser Pole Arrester

OpenPoint


Lateral Tapped Cable, Riser Pole, and Open-End Arresters

OpenPoint


Lateral Tapped Cable, Riser Pole, Open-End Arresters, and Tap-Point Arrester

OpenPoint


Riser Pole Plus Cable-End Arrester

OpenPoint


Riser Pole, Cable-End, and Third Arrester

OpenPoint


Riser Pole Arrester and Under-Oil Arresters at Every Pad-Mounted Transformer

OpenPoint

Under-OilArrester

FIGURE 5.51: Arrester Locations.

228 – Sect ion 5

let-through voltage. Simulations and laboratorytests have shown that maximum cable surgevoltage will be reduced by 25 percent with theaddition of cable-end arresters.

In most instances, 25-kV system protectivemargins obtained with this arrester configurationare less than the recommended 20 percent level.If protective margins of 20 percent or more aredesired, additional arresters must be added toprotect cable and equipment remote from thetwo end points.

Riser Pole, Cable-End, and Third Arrester(Figure 5.51, No. 3)Additional surge protection can be provided byadding a third arrester between the two ends ofthe cable. The function of the third arrester is tosuppress the voltage spike reflected from thecable-end arrester. For limiting surge voltage ex-posure to a minimum, the most effective loca-tion for the arrester is the first transformer onthe source side of the cable-end arrester. Theseparation distance between the two protectivedevices must be at least 200 to 300 feet for thethird arrester to effectively suppress the reflectedwave. If the first transformer upstream from theopen point is fewer than 200 feet away, thethird arrester can be applied at the next up-stream transformer, leaving the first unit with re-duced protection. The maximum system surgevoltage with third arrester protection can be cal-culated using Equation 5.26.

Equation 5.26 shows that, except for the cablesection between the third and cable-end ar-resters, the maximum system surge voltage islimited to the protective level provided by theriser pole arrester (Lat, 1987).

5

Equation 5.26

VC = VRP + VL

where: VC =Maximum cable and equipmentsurge voltage, in kV


VL = Lead voltage drop, in kV

Lateral Tapped Cable with Riser Pole Arrester(Figure 5.51, No. 4)Cooperatives sometimes tap a radial cable sys-tem to provide service to nearby loads. Tappingthe cable produces parallel cable runs wheresurge voltages can propagate independently. Atapped configuration will produce higher cablevoltages than will a simple radial system becausemultiple traveling waves can add and subtract incomplex ways.

Assume a voltage surge enters the tapped sys-tem at the riser pole with no other arresters ap-plied. When the surge reaches the tap point, itsees an equivalent surge impedance of approxi-mately 15 to 20 ohms. The impedance is the par-allel combination of the surge impedance of eachcable leg. Because of the discontinuity, portionsof the incident wave will be reflected back to-ward the riser pole and simultaneously refractedonto the two cable legs. When the two refractedvoltage waves reach the respective cable ends,they will double and travel back to the tappoint, where they will again be reflected and re-fracted. Because of the unequal travel times onthe cable sections, the multiple reflections andrefractions will ultimately lead to an increase incable-end voltage. The voltage increase can beup to 30 percent more than the voltage doublingnormally experienced on a radial cable run pro-tected only by a riser pole arrester.

Lateral Tapped Cable, Riser Pole, and Open-End Arresters (Figure 5.51, No. 5)Installing MOV arresters at both open points willreduce their voltages to the protective level of thearresters. Arresters at the end points will also keepthe tap-point voltage within reasonable magni-tudes. In one laboratory test, the tap-point voltagewas 13 percent higher than the maximum mid -span voltage on a radial system under the sameconditions (riser pole and cable-end arrester).

Lateral Tapped Cable, Riser Pole, Open-EndArresters, and Tap-Point Arrester (Figure 5.51, No. 6)Placing an arrester at the tap point will tend tofurther reduce voltages along the tapped feeder.This is due to the shunting effect of the arresterto limit the initial surge as well as the reflected


waves. A more definite statement cannot be madeunless a specific example is analyzed in detail.

An arrester at the tap point should not be con-sidered as adequate protection for the two opencable ends. Tests have shown that positive wavereflections can act to more than double the ca-ble-end voltage, when compared with a tappedsystem protected by a riser pole arrester only.

The following general conclusions can bedrawn from investigations into the effects ofcable taps on surge voltage magnitudes:

• A primary tap will increase surge voltagemagnitudes above levels that will exist with-out a tap.

• The surge voltage magnitude increase willtypically be 10 to 30 percent.

• Taps located close to the riser pole tend toproduce greater surge voltage magnitudes.

• Multiple taps do not appear to produce surgemagnitudes significantly greater than a singletap (Ros, 1988).

Riser Pole Arrester and Under-Oil Arresters at Every Pad-Mounted Transformer (Figure 5.51, No. 7)The ultimate surge protection scheme is to pro-vide arresters at every convenient and accessiblepoint on the underground system. Besides theriser pole, possible locations could be tappoints, sectionalizing points, and pad-mountedtransformers. The arresters have to be dead-front

5

Voltage Feeder Configuration Arrester Locations

12.47 kV Radial Riser PoleOpen Point

25 kV Radial Riser PoleOpen PointThird Arrester Near Open Point*

12.47 kV Tapped Lateral Riser PoleOpen Points

25 kV Tapped Lateral Riser PoleOpen PointsTap Point*

*Optional application

TABLE 5.14: Recommended Arrester Locations.

or under-oil designs, which are very expensiveto add to existing installations. However, someutilities are considering under-oil arresters forevery new or replacement transformer installa-tion as a way to prolong cable life. Under-oil ar-resters are good; however, one must considerthe cost to replace an under-oil arrester when itfails, and some will fail. Replacing under-oil ar-resters can be very expensive. It does, however,remain to be seen whether this overall schemewill prove to be a cost-effective approach.

RECOMMENDED ARRESTER LOCATIONS AND RATINGSThe information presented above has shown thatmany factors affect arrester protective margins. Itis not possible to consider all factors in an appli-cation because they can change for many differ-ent reasons. Experience has shown that therecommendations in Table 5.14 should be usedfor radial feeders and tapped laterals for conser-vative underground protection.

The recommended arrester locations given inTable 5.14 are based on the application of riserpole MOV arresters with 10-kV and 21-kV duty-cycle voltage ratings. The MCOV for these ar-resters is 1.17 pu and 1.18 pu of nominal line-to-neutral system voltage. The recommended voltageratings are one step above the 9-kV and 18-kVratings that can be used on effectively groundedneutral circuits that have close voltage regulation(Range A voltage levels).

Distribution systems are susceptible to long-term overvoltages caused by the following:

• Line-to-ground faults,• Poor voltage regulation,• Line voltage regulator malfunctions,• Ferroresonance,• Fixed shunt capacitors, including long cables,• Circuit backfeed,• Load rejection, and • Other system contingencies.

The lower-rated arresters provide additionalprotective margin, especially at 25 kV. However,the higher-rated arresters are recommended toprevent premature arrester failures as the instal-lation ages. The following examples will show

230 – Sect ion 5

PRACTICAL DEAD-FRONT ARRESTERINSTALLATIONSThe introduction of dead-front MOV arrester de-signs and their accessories for use inside UD en-closures has introduced flexibility into under-ground system protection. Product evolution nowallows choices in the selection of optimum protec-tion schemes based on cost and protection levels.In the previous discussion of protection methodsand arrester locations, four locations were sug-gested for the installation of dead-front arresters:

1. On the cable end at the open-point trans-former between two sections of a loop-feedcircuit,

2. At the first upstream transformer from theopen point,

3. At a tap point, and4. At the cable end of a lateral tap (radial-feed

circuit).

The following will describe practical ways tophysically connect arresters at all four locationsusing load-break elbow-type connectors andelbow, bushing, and parking stand arresters de-scribed previously in the subsection, Dead-FrontLightning Arresters. To get flexibility with dif-ferent arresters and components, purchase onlytransformers with bushing wells.

Cable-End Arrester at Open PointThree configurations can be used for this instal-lation. The configuration chosen will depend onoperating practices and available space insidethe pad-mounted transformer cabinet.

Figure 5.52(a) shows an open-point trans-former with an arrester attached to each cableend. The arrangement uses two elbow-type ar-resters and a feed-through mounted on the park-ing stand. This installation takes up the mostroom on the transformer faceplate.

Figure 5.52(b) shows a different approach thatcan be taken at the open-point transformer. Ituses an elbow arrester and a parking stand ar-rester to reduce overcrowding by eliminating thefeed-through device.

The third configuration, Figure 5.52(c), allowsincreased operational flexibility and reducesovercrowding by using bushing and parking

5

FIGURE 5.52: Cable-End Arresters at Open Point.

Feed-ThroughH1A H1B

Elbow ArresterElbow Arrester

To Riser Pole To Riser Pole

(a) Two Elbow Arrester and a Feed-Through

H1A H1B

Elbow Arrester

Elbow Connector

Parking StandArrester


(b) Elbow Arrester and Parking Stand Arrester

H1A H1B

Insulating CapBushing Arrester

Parking StandArrester


(c) Bushing Arrester and Parking Stand Arrester

that using the recommended arrester locationsand voltage ratings will result in higher protec-tive margins than those suggested by standards.


stand arresters. Operational flexibility is obtainedbecause the open point can be closed by mov-ing the parked cable to H1B without removingthe parking stand arrester. Once a cable fault isrepaired, the elbow connector is easily placedback on the parking stand arrester to reestablishthe open point. The bushing arrester on H1A re-quires less space than an elbow arrester/feed-through bushing insert combination mounted inthe same location.

Arrester Upstream from Open PointTwo arrester configurations may be used to pro-vide additional protective margins at 25-kV andabove by clipping the voltage spike generated byoperation of the open-point arrester. An elbowarrester or a bushing arrester may be applied.Figure 5.53(a) is a schematic of how an elbowarrester combined with a feed-through bushinginsert can be mounted on the transformer face-plate. To reduce clutter inside the enclosure,mate a bushing arrester to the source-side cableas shown in Figure 5.53(b). Figures 5.54 through5.58 show the five installation configurations dis-cussed above.

Lateral Tap Cable-End ArresterFor lateral taps off all underground feeders, ar-resters should be placed at open points to pre-vent reflections from increasing surge voltagesabove levels that would exist without the tap(s).Figure 5.59 shows the desired ways arresters canbe applied to two- and single-bushing transform-ers at the end of radial-feed circuits. To addsurge protection to a two-bushing loop-feedunit, an elbow arrester or a bushing arrestermust be connected to the unoccupied terminal.For the radial-feed transformer, the least-cost ap-plication is to add a bushing arrester.

Tap Point ArresterFor tapped lateral feeder configurations 25 kVand above, an arrester should be added at thetap point as well as on the open points. Manyconnection methods can be used, but the oneshown in Figure 5.60 offers a simple, low-costapproach to establish a tap point, have load-break switching capability, plus add an arrester.The cable-to-cable connections can be made by

5

FIGURE 5.53: Arrester Upstream from Open Point (Third Arrester).

H1A H1B

Elbow Arrester

Feed-ThroughBushing Insert

To Riser Pole To Open Point

(a) Elbow Arrester on Feed-Through Insert

H1A H1B

Elbow ConnectorBushing Arrester

To Riser Pole To Open Point

(b) Bushing Arrester Only

FIGURE 5.54: Two Elbow Arresters and a Feed-Through.

Primary Source Alternate Source

H1B

H1A

X3

X1

X2

232 – Sect ion 5

using a four-point load-break junction bolted tothe inside surface of a suitable pad-mounted en-closure. The three cables are connected togetherusing load-break elbow connectors attached tothree terminals of the junction. An elbow surgearrester is installed on the fourth terminal tocomplete the installation.

UNDERGROUND SURGE PROTECTIONEXAMPLESThe five examples in this subsection are basedon a typical underground loop feed to a subdivi-sion with an open point between the two later-als. Only one underground radial with fourpad-mounted transformers will be investigated.The system is protected by a riser pole MOV ar-rester with discharge characteristics that arereadily available within the industry. Dead-frontarresters are used at strategic locations for in-creased protective margins. Arrester lead lengthsare assumed to be one foot at the riser and threefeet at the pad-mounted transformer locations.Various surge current waveshapes and magni-tudes are used to evaluate the effectiveness ofthe different recommended protective schemes.The many calculations were made by a travel-ing-wave computer program (Cooper Power Sys-tems’ UDSURGE™).

A simplified schematic of the system is shownin Figure 5.61.

5

FIGURE 5.55: Elbow Arrester and Parking Stand Arrester.


H1B

H1A

X3

X1

X2

FIGURE 5.56: Bushing Arrester and Parking Stand Arrester.


H1B

H1A

X3

X1

X2

FIGURE 5.57: Elbow Arrester on Feed-Through Insert onTransformer Upstream from Open Point.

Primary Source To Open Point

H1B

H1A

X3

X1

X2

FIGURE 5.58: Bushing Arrester on Transformer Upstreamfrom Open Point.

Primary Source To Open Point

H1B

H1A

X3

X1

X2


5

FIGURE 5.59: Lateral Tap Cable-End Arrester (Radial Feed Circuit).

FIGURE 5.60: Tap-Point Arrester. FIGURE 5.61: Typical Underground Subdivision Loop Feed withOpen Point.

Two-Bushing Pad-Mounted Transformer

Single-Bushing Pad-Mounted Transformer

H1A H1A

Elbow Arrester

Bushing Arrester

To Tap Point To Tap Point

H1B

Pad-Mounted Enclosure

Four-Point Load Break Junction

Elbow Arrester

Tap Line

To Open PointTo Riser Pole

Surge Voltage Magnitudes Calculated at Riser Pole and the 4 Pad-Mounted

Transformer Locations

Riser Pole ArresterProtecting Jacketed CableUnderground Lateral: 12.47 kV and 25 kVArrester Ratings: 10 kV and 21 kVTotal Arrester Lead Length = 1 Foot

Dead-Front Arrester Locations

Ratings: 10- and 21-kV3-Foot Leads

Pad#1

Pad#2

Pad#3

Pad#4

OpenPoint

Conduit

1,000' 400' 400' 400'

Tables 5.15 through 5.19 summarize the surgevoltages calculated by the computer program atthe riser pole and the four transformer locations.Different surge current characteristics are usedto illustrate how variable lightning characteris-tics can affect equipment protective margins.Varying the current rate-of-rise and magnitude

and calculating the voltage at all nodes enablesmost of the variables that go into the protectivemargin (lightning variability, arrester characteris-tics, lead length, BIL deterioration, reflections,and so forth) to be considered. In this way, forthis particular system, recommended arrester lo-cations can be evaluated on their merits.

234 – Sect ion 5

5EXAMPLE 5.15: MOV Riser Pole Arrester: Arrester Rating, 10 kV.

Table 5.15 considers a 12.47-kV system protected bya 10-kV MOV riser pole arrester. ANSI Standards sug-gest a 20 percent margin for an 8 × 20 µs surge at10 kA. Most protection engineers realize this sug-gestion does not consider many of the variables men-tioned in the previous paragraph and is used mostlyon overhead systems. To provide added security inunderground applications, many engineers double thecurrent magnitude to 20 kA. If a 20 percent or greatermargin is obtained, the system is considered ade-quately protected. Under these conditions, Table 5.15shows protective margins of 46 and 31 percent, re-spectively, for aged insulation. Further examinationreveals that, for the two fast-front, high-magnitudecurrent surges depicted in the last two rows of thetable, the margin is reduced below 20 percent andactually becomes negative for the worst case.

Protective margin calculations at any of the other lo-cations on the radial feeder are simple to make. Thelisted surge voltage magnitudes include lead voltagedrop. Protective margin is then simply as shown inEquation 5.27.

Surge Surge Voltage Magnitudes (kV)Current Padmount Padmount Padmount Padmount

Characteristics Riser Pole No. 1 No. 2 No. 3 No. 4

8 × 20 µs 26.9 50.1 51.4 51.9 52.1 10 kA (46% margin)

8 × 20 µs 29.7 56.0 57.4 57.9 58.2 20 kA (31% margin)

1 × 50 µs 36.4 64.1 64.2 64.4 71.9 20 kA (6% margin)

1 × 50 µs 54.8 87.8 88.0 88.4 108.1 50 kA (-30% margin)

Note. Percent margins in parentheses are for aged insulation BIL.

TABLE 5.15: MOV Riser Pole Arrester: Arrester Rating, 10 kV;Equipment BIL, 95 kV; Aged BIL, 76 kV.

Equation 5.27

PM(%) = × 100–1 BIL

Surge Magnitude

EXAMPLE 5.16: MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4): Arrester Rating, 10 kV.

The system in Table 5.16 is pro-tected with a riser pole arresterand a cable-end arrester. Placingthe arrester at the end of thecable prevents voltage doublingand keeps a minimum 39 percentmargin for aged insulationthroughout the entire length of thecable in the worst case. Cable-end arresters are strongly recom-mended at 12.47 kV to protectequipment insulation from fast-front, high-magnitude lightningsurges.



8 × 20 µs 26.7 38.2 37.1 34.9 28.310 kA (99% margin)

8 × 20 µs 29.6 41.6 40.2 36.8 29.420 kA (83% margin)

1 × 50 µs 36.4 43.5 43.5 43.7 36.920 kA (74% margin)

1 × 50 µs 54.8 54.6 54.5 54.3 37.2 50 kA (39% margin) (104% margin)


TABLE 5.16: MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4):Arrester Rating, 10 kV; Equipment BIL, 95 kV; Aged BIL, 76 kV.


5



8 × 20 µs 56.6 103.5 106.5 107.9 108.6 10 kA (-7% margin aged)

(16% margin new)

8 × 20 µs 62.3 115.6 119.0 120.2 120.5 20 kA (-17% margin aged)

(4% margin new)


TABLE 5.17: MOV Riser Pole Arrester: Arrester Rating, 21 kV; Equipment BIL, 125 kV; AgedBIL, 100 kV.

EXAMPLE 5.17. MOV Riser Pole Arrester: Arrester Rating, 21 kV.

The summary of surge cur-rent magnitudes for a 25-kVlateral protected by an MOVriser pole arrester rated 21kV is shown in Table 5.17.The standard 8 × 20 µswaveform with 10- and 20-kA magnitudes producesnegative margins for agedinsulation and less than 20percent margin for new in-sulation. This example reit-erates that a riser polearrester cannot protect a25-kV radial cable with anopen-point termination.

EXAMPLE 5.18: MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4): Arrester Rating, 21 kV.

The example in Table 5.18represents a 25-kV systemwith arresters located at theriser pole and open point. Thearresters limit the voltage toacceptable levels at bothcable ends. Voltage magni-tudes on the interior cablesection cause inadequatemargins for the 8 × 20 µs,20-kA case and both fast-front, high-current cases.The higher voltages in themiddle of the cable arecaused by the addition of thedead-front arrester valve-onvoltage to the reflected volt-age traveling back towardthe sending end of thecable. For further informa-tion, refer to the earlier ex-planation of traveling waves.



8 × 20 µs 55.9 79.8 77.5 73.0 57.010 kA (25% margin)

8 × 20 µs 61.8 85.1 82.4 75.8 58.120 kA (18% margin)

1 × 50 µs 66.4 90.8 90.9 91.2 72.020 kA (10% margin)

1 × 50 µs 89.5 98.6 98.8 99.2 70.4 50 kA (1% margin aged) (42% margin)

(26% margin new)


TABLE 5.18: MOV Riser Pole Arrester and Dead-Front Cable-End Arrester (No. 4): ArresterRating, 21 kV; Equipment BIL, 125 kV; Aged BIL, 100 kV.

236 – Sect ion 5

Some protection engineers recommend riserpole and open-end arresters at 25 kV. A two-ar-rester protection scheme is adequate for mostlightning conditions. However, field tests haveshown fast-front high-magnitude surges canoccur 20 percent of the time (see Figure 5.43.)

To protect against these lower probabilityevents, the three-arrester scheme is recom-mended for underground installations. It is aconservative approach that balances increasedarrester costs against increased MOV arresterand cable life.

5EXAMPLE 5.19: MOV Riser Pole Arrester Plus Dead-Front Cable-End Arrester (No. 4) and Dead-Front Third Arrester (No. 3):Arrester Rating, 21 kV.

The example in Table 5.19shows the addition of adead-front arrester to thenext transformer upstreamfrom the open point. This ar-rester at transformer No. 3cancels the valve-on voltagespike from the open-end ar-rester. The three arrestersworking together provideacceptable protective mar-gins along the entire cablelength.

Surge Surge Voltage Magnitudes (kV)

Current Padmount Padmount Padmount Padmount Characteristics Riser Pole No. 1 No. 2 No. 3 No. 4

8 × 20 µs 55.9 64.2 61.5 57.0 57.010 kA (55% margin)

8 × 20 µs 61.2 68.0 64.7 57.9 58.020 kA (47% margin)

1 × 50 µs 66.4 69.7 67.3 66.6 71.9 20 kA (39% margin)

1 × 50 µs 89.5 89.3 89.0 68.7 70.350 kA (12% margin aged)

(40% margin new)


TABLE 5.19: MOV Riser Pole Arrester Plus Dead-Front Cable-End Arrester (No. 4) and Dead-Front Third Arrester (No. 3): Arrester Rating, 21 kV; Equipment BIL, 125 kV; Aged BIL, 100 kV.


1. The purpose of the grounding system is tomaintain all points connected to it at earthpotential under various conditions.

2. The grounding system consists of thegrounding and neutral circuits. The ground-ing circuit is made up of ground electrodes,ground conductors, and all connections. Theneutral circuit includes the JCN and all con-nections to it.

3. The return current path must be a continu-ous metallic circuit along the entire route ofenergized conductor(s). The earth shouldnever be used as the only path for the returnof normal load current.

4. Under fault conditions, the neutral circuitprovides a low resistance path to ensure

fast operation of protective devices. It alsoprevents dangerous touch potentials onequipment cases and frames.

5. A ground rod has a 60-Hz measured resis-tance and a surge impedance (ZSURGE).ZSURGE is defined as the ratio of the peakvoltage to current on the rod caused by alightning discharge.

6. ZSURGE is always less than, or essentiallyequal to, the rod’s 60-Hz resistance value.

7. When a riser pole arrester conducts, light-ning surge current flows on the followingcomponents:

a. Arrester leads,b. Pole ground conductor,


c. Jacketed cable neutral,d. Counterpoise, ande, Overhead multigrounded system neutral.

The surge currents produce undesirable effects that, except for arrester lead length,are reduced by a low ground rod resistancewhen compared with the surge impedancesof the various paths.

8. Low ground rod resistance will reduce jacketvoltage and the amount of surge currentflowing on the JCN to the transformer andservice neutrals.

9. Continuous counterpoise connected to theJCN at the pole top and extended to thetransformer ground rod will reduce jacketvoltage up to 50 percent.

10. Take special measures to adequately groundJCN cable installations when compared withsemiconducting jacketed and BCN cablesystems.

11. Ground rods are the primary means to re-duce ground resistance on JCN cable instal-lations. The three factors that affect groundresistance are the following:

a. Length,b. Number of rods, andc. Spacing.

12. Where possible, use longer rods, not multi-ple rods, to lower ground resistance.

13. When multiple rods are used because ofrocky soil, space them at least two rodlengths apart.

14. The required number of driven rods for aJCN cable installation is set by the NESC.Table 5.2 summarizes ground rod rules andrequirements.

a. Power cable only: four rods per mile.b. Random lay: eight rods per mile.c. Counterpoise is considered a made

electrode.

15. Ideally, the riser pole ground resistanceshould have the lowest value, followed bythe transformer ground rod, and then theservice ground.

516. Counterpoise will reduce jacket voltages.

The counterpoise should be attached at thecable termination for best results.

17. Continuous counterpoise should be installedto the first transformer, if practical.

18. If full-length counterpoise is not justified,100- to 300-foot lengths should be used.

19. An ideal ground has a low ground resistancevalue. To measure the ground resistance,one of the testers listed in Table 5.20 shouldbe used.

Type of Grounding Clamp-On* 3-Point** 4-Point** System Meter Meter Meter

Single X X XGround Rod

Multiple X X XGround Rod

Counterpoise X

* Measurement must be made with the ground undertest connected to a multigrounded system.

**Measurement must be made before connecting theground under test to the system ground.

TABLE 5.20: Ground Resistance Testers.

20. Soil resistivity directly affects ground resistance.Therefore, an engineer will need the soil resis-tivity value before designing a grounding sys-tem. If this information is not available, thesoil resistivity should be measured using afour-point earth resistance tester.

21. Counterpoise and ground rods should be in-stalled below the frost line. Doing so helpsprevent an increase in ground resistancecaused by frozen soil.

22. If possible, counterpoise and ground rodsshould be placed in an area with permanentmoisture content. When the surrounding soildries out, the ground resistance of the coun-terpoise or ground rod increases.

23. Ground resistance calculations should beused to compare different ground systemconfigurations. If the ground resistance valueis high, it should be decreased by:

238 – Sect ion 5

a. Increasing the length of the ground rod or counterpoise, or

b. Increasing the number of ground rods.

24. MOV arresters should be used for riser pole applications because they provide better protective margins than do similar SiC designs.

25. Series and shunt-gapped MOV riser pole arresters have better temporary overvoltagecapability and slightly better protective char-acteristics than gapless models. They shouldbe considered in areas where inadequatevoltage regulation occurs.

26. Dead-front lightning arresters should be applied close to protected equipment on underground systems to increase protectivemargins.

27. Light-duty dead-front arresters should be coordinated with riser pole arresters so theirdischarge capability is not exceeded becauseof current sharing. Short riser pole leads andduplicate voltage ratings help ensure propercurrent sharing.

28. Selection of MOV arrester voltage rating isbased on the MCOV the arrester sees duringnormal service.

29. Maximum voltage rise on the unfaultedphases of a loaded three-phase circuit andvoltage regulation on distribution feedersabove five percent can cause long-termovervoltages on MOV arresters. When un-sure about overvoltage duration, choose thenext higher MOV arrester rating (10 kV and21 kV rather than the usual 9 kV and 18 kV).

30. Protective margin depends on protectivecharacteristics of the arrester, lightning surgecurrent magnitude, and equipment BIL.

31. Protective margin is calculated using Equation 5.17:

5

PM(%) = –1 BIL

IR + LV× 100

32. Standards recommend using an average risetime (di/dt) of 4 kA/µs when calculating lead

voltage. When this value is multiplied by 0.4µH/ft, it gives 1.6 kV/ft lead voltage, whichis the value to use with 8 × 20 µs arresterdata. Recent studies have shown this valueshould be somewhere between four to eightkilovolts per foot when using arrester FOWcharacteristics to calculate protective margin.

33. Arrester lead lengths must be kept as shortas physically possible to obtain the maximumprotective margin. For riser pole installations,this is accomplished by making connectionsto the arrester terminals first, and then to theconductor and ground terminals of the cabletermination.

34. It is important to remember how an incidenttraveling voltage wave reacts when it meetsa change in surge impedance at a junctionpoint such as an open point, midpoint cabletap, or MOV arrester.

35. If the junction point is an open circuit (infinitesurge impedance), the reflected voltage is posi-tive and produces a voltage doubling effect.If this line is terminated in a short circuit, thereflected voltage is negative, which cancelsthe incoming wave. For a line terminated byan MOV arrester, voltage doubling does notoccur, but the reflected voltage is increasedby one-half the arrester valve-on voltage.

36. Necessary and optional arrester locationsthat will minimize cable and transformerovervoltages should be used.

37. After the decision is made where to placethe arresters, elbow, bushing, and parkingstand dead-front arresters should be physi-cally connected at the following:

a. Open-point transformer between two sections of a loop-feed circuit,

b. First upstream transformer from the open point,

c. Tap point, andd. Open end of a lateral tap.

38. MOV arrester voltage ratings of 10 kV and 21 kV may be used instead of 9-kV and 18-kVunits, if problems are encountered withovervoltages.

Ferroresonance – 239

Ferroresonance6In This Section:

Before the use of primary voltages above 15 kVin overhead systems, and before the use ofmedium-voltage power cables for primary distri-bution circuits, engineers designing and operat-ing distribution systems were not concernedwith ferroresonance. However, when 24.9-kVand 34.5-kV phase voltage lev-els were introduced for over-head distribution systems,ferroresonance occurred dur-ing the switching of smalltransformer banks at their pri-mary terminals. Correspond-ingly, when shielded cables

were used instead of bare overhead conductorsfor primary circuits—operating at any voltagelevel—ferroresonance occurred during theswitching of the cable circuit and the distribu-tion transformers connected to them.Ferroresonance in underground systems re-

sults from single phasing inthree-phase primary circuitswith distribution transformers,which establishes configura-tions where the capacitancesof the primary circuit and thenonlinear inductances of thetransformers are arranged so

Allowable Overvoltages During Ferroresonance

Distribution Transformer Connections

Qualitative Description of Ferroresonance

Ferroresonance When Switching at the Primary Terminals ofOverhead and Underground Transformer Banks

Ferroresonance with Cable-Fed Three-Phase Transformers withDelta or Ungrounded-Wye Connected Primary Windings

Ferroresonance with Cable-Fed Three-Phase Transformers withGrounded-Wye Primary Winding and Five-Legged Core

Ferroresonance with Cable-Fed Three-Phase Transformers withGrounded-Wye Primary Windings and Triplex Construction

Ferroresonance in Underground Feeders Having More Than One Transformer

Summary of Techniques for Preventing Ferroresonance in Underground Systems


References

Single phasing in

three-phase primary

circuits can cause

ferroresonance.

240 – Sect ion 6

that nonlinear resonance canoccur. Single-phase conditionsoccur during the normal oper-ation of fused or nonfused dis-connects, elbow connectors,single-pole reclosers, and sin-gle-pole sectionalizers whencircuits and their connectedtransformers are energized andde-energized. Single phasing also occurs if a sys-tem component fails in a way that produces anopen conductor condition. Ferroresonance maycause very high overvoltages that damageequipment and cause failures.Those responsible for the design and opera-

tion of rural distribution systems need to be fa-miliar with ferroresonance to prevent extremelyhigh ferroresonant overvoltages from occurringduring single-phase conditions in the primarythree-phase systems.Experience and previous guidelines for avoid-

ing ferroresonance are not always good indica-tors of conditions in which ferroresonance mayoccur. Most guidelines predate the present wide-spread evaluation of losses by utilities in thetransformer procurement process. No-load losseshave a direct effect on the ferroresonance sus-ceptibility of a transformer, and the substantialdecrease in transformer losses in recent yearsmakes the transformers of today much moresusceptible to ferroresonance than those in usewhen previous ferroresonance guidelines weredeveloped. A major investigation of ferroreso-nance in modern grounded-wye pad-mountedtransformers was completed in 1992. This inves-tigation, sponsored by the Distribution SystemsTesting, Application, and Research (DSTAR)consortium, of which NRECA is a member, hasobtained results showing that some previousguidelines about ferroresonance are not valid for

6newer low-loss transformers,and has generated updatedferroresonance avoidanceguidelines. The findings of thisresearch, including the newguidelines, have been incorpo-rated into this section.Field experience has shown

that overvoltages occurringduring ferroresonance can cause failure of bothmetal oxide and gapped silicon carbide surge ar-resters, distribution transformers, cables, elbowconnectors, splices, and equipment connectedto the secondary side of the distribution trans-former, including consumer appliances, comput-ers, and electronic home entertainment equip-ment. System designs and transformer connec-tions that are prone to ferroresonance should beavoided wherever possible. If the system designor topology does not eliminate the chance offerroresonance under all possible switching con-ditions, operating personnel must be able to rec-ognize when ferroresonance may occur duringsingle-pole switching of cable circuits with con-nected transformer(s) and know how to section-alize and switch the system so that ferroreso-nance will not occur.This section provides the system designer

with information needed to design a systemin which ferroresonance is less likely. It identi-fies the distribution transformer connections thatare highly susceptible to ferroresonance duringsingle-phase switching. Under some circum-stances, it may not be possible to design a sys-tem in which ferroresonance is prevented forany switching procedure or sequence selectedby operating personnel. However, certain switch-ing procedures and sequences will minimize thechance of ferroresonance during normal switch-ing operations.

Modern low-loss

transformers are much

more susceptible to

ferroresonance.

AllowableOvervoltagesDuringFerroresonance

Most rural primary distribution systems operat-ing at nominal phase voltages up to and includ-ing 35 kV (line-to-ground voltages up to 20 kV)are multigrounded neutral systems. Each pri-mary feeder in these systems, whether overheador underground, and whether single-phase, vee-phase, or three-phase, has a neutral conductor

that is grounded at least four times per mile. Asnoted in Section 5, codes in some states requirethat the neutral conductor be grounded morefrequently than four times per mile.When ground faults occur on the primary

feeder of these systems, the voltage betweenany unfaulted phase and the neutral conductor


will rise above the nominal line-to-neutral voltagefor the system. For overhead construction withconductors on an eight-foot or longer crossarm,or primary feeders with concentric neutral cables,the voltages from the unfaulted phases to theneutral conductor in a typical rural system willnot exceed 1.25 times the nominal line-to-neu-tral voltage (1.25 per unit or pu). If the primaryfeeders employ spacer cable or armless con-struction, which is not common on most ruralsystems, the voltage from an unfaulted phase tothe neutral conductor can exceed 1.25 pu, risingas high as 1.46 times nominal value (1.46 pu).The 1.25-pu voltage present during ground

faults is the basis for selecting the duty cyclevoltage rating of the surge arresters applied onmost rural distribution systems. Arrester dutycycle ratings are at least 1.25 times the system

6nominal line-to-neutral voltage. For example, ona 12.47/7.2-kV rural system, the duty cycle volt-age rating of the surge arrester is either nine or10 kV. The wide acceptance of this applicationguide for surge arrester voltage rating acknowl-edges that the equipment connected from phaseto neutral on rural distribution systems is sub-jected to and can tolerate temporary line-to-neutral overvoltages of 1.25 times nominal. This1.25-per-unit overvoltage is also the upper limiton the temporary overvoltages that can be permit-ted during single-phase switching in rural distribu-tion systems. The application tables and equationsin this section for determining the allowablecable lengths during the switching of cable cir-cuits and connected transformers are based onlimiting temporary overvoltages to 1.25 pu.

DistributionTransformerConnections

Ferroresonance in distribution systems occursduring the single phasing of circuits, usuallyunderground cable circuits, and their connecteddistribution transformers. Whether ferroreso-nance is possible—as well as the maximumallowed length of a circuit with a connectedtransformer that can be switched with single-pole switches without exceeding 1.25-pu voltage—depend on the connections of the distributiontransformer primary windings. Certain windingconnections are highly susceptible to ferroreso-nance, whereas other winding connectionsprevent ferroresonance under all practicalconditions.Figure 6.1 shows the more common trans-

former connections found in rural distributionsystems.The delta/grounded-wye connections and the

grounded-wye/grounded-wyeconnections in Figures 6.1(a)and (b) are used to supplyfour-wire wye secondary sys-tems, operating at nominalvoltages of either 208Y/120volts or 480Y/277 volts. Thesewinding connections are usedin three-phase transformersand in banking three single-phase transformers.

The transformer connections shown in Fig-ures 6.1(c), (d), (e), and (f) are used to supplyfour-wire delta secondary systems, operating ata nominal voltage of 240/120 volts. The open-delta/open-delta connections and the open-wye/open-delta connections usually are made fromtwo single-phase distribution transformers, al-though some “three-phase” transformers havebeen made with the open-wye/open-delta con-nections. The delta/delta and the ungrounded-wye/delta connections are found in somethree-phase transformers, and are used in con-necting single-phase transformers into three-phase banks. In the four-wire delta secondarysystems, the three-phase, three-wire load is sup-plied phase-to-phase at 240 volts, and the sin-gle-phase, three-wire 120/240-volt lighting loadis connected across the secondary winding with

the center tap and secondaryneutral conductor.As discussed in detail later

in this section, transformerswith ungrounded primarywindings (delta, open-delta,and ungrounded-wye) arehighly susceptible to ferro-resonance during single-phaseswitching in underground sys-tems. In contrast, three-phase

With certain distribu-

tion transformer

winding connections,

ferroresonance is

very likely during

single phasing.

242 – Sect ion 6

transformers or transformer banks with thegrounded primary windings (grounded-wye oropen-wye) are less susceptible to ferroresonance

and may even prevent ferroresonance fromoccurring, depending on construction of thethree-phase transformer or transformer bank.

6

FIGURE 6.1: Transformer Connections for Four-Wire Wye and Four-Wire Delta Services.

P S

Neutral

(c) Delta/Delta(a) Delta/Grounded-Wye (b) Grounded-Wye/Grounded-Wye

(d) Ungrounded-Wye/Delta (e) Open-Delta/Open-Delta (f) Open-Wye/Open-Delta

NeutralNeutral

Neutral Neutral Neutral

P S P S

P S P S P S

P = PrimaryS = Secondary

QualitativeDescription ofFerroresonance

DEFINITIONFerroresonance is a complex electrical phenome-non in electrical circuits having at least one non-linear inductor and at least one linear capacitorthat is fed by one or more voltage sources havinga sinusoidal waveshape. The nonlinear inductoris a saturable circuit element such as an iron coretransformer. When ferroresonance occurs from aswitching operation to energize or de-energize acircuit, an initial transient response may eventu-ally settle into a sustained steady-state response.In general, the steady-state voltage and currentwaveforms are not sinusoidal like those of thesource voltage.There can be more than one steady-state re-

sponse mode in a specific circuit. The steady-statemode may depend on the initial or transientconditions in the circuit. Ferroresonance can bea chaotic phenomenon, meaning that a switch-ing event repeated identically on the same cir-cuit yields results that are substantially different.The circuit may never settle into a steady-statecondition and may erratically jump from onemode to another indefinitely.

First, review the response of the series resis-tive-inductive-capacitive (RLC) circuit with linearparameters, and second, look at the effect of anonlinear inductor in the circuit. With this back-ground, it is then possible to consider the effectsof this phenomenon on the distribution system.

RESONANCE IN THE LINEARINDUCTIVE-CAPACITIVE CIRCUITFigure 6.2 shows a series RLC circuit, in whichthe resistor, inductor, and capacitor are linear.Linear means that the resistance, inductance,and capacitance of the elements do not changewith time, current, or any other parameter. Thesource is a sine wave voltage with a peak mag-nitude of VM, having a frequency of ω radiansper second. In the 60-Hz system, the radianfrequency is 377 radians per second.The circuit is energized by closing switch S1 at

time zero. Following switch closure, the current inthe circuit and the voltage across each elementconsist of a steady-state response and almostalways a transient response. The transient re-sponse decays with time to zero, leaving just the


Equation 6.1 gives the rms value of the cur-rent in the circuit.In Equation 6.1, ωL is the inductive reactance,

XL, and 1/ωC is the capacitive reactance, XC, withboth reactances having units of ohms. When theinductive reactance ωL is equal to the capacitivereactance, 1/ωC, the denominator of the equationhas a minimum value equal to R, the circuit resis-tance, and the current in the circuit has a maximumvalue equal to Vrms/R amperes. Also, at this point,the input impedance to the circuit of Figure 6.2 ispurely resistive and the circuit is in resonance.If the inductance L and capacitance C are con-

stant, the frequency at which resonance occursis called the resonant frequency. The resonantfrequency, designated as ω0 in radians per sec-ond, is given by Equation 6.2.During resonance, the voltage across the resis-

tor is at its maximum possible value and equalto the source voltage, Vrms. The magnitudes ofthe voltage across the inductor and capacitor at

6

FIGURE 6.2: Series RLC Circuit with Sinusoidal Excitation.

XL = Inductive reactance

ω = Frequency of the system, in radians per second

XC = Capacitive reactance

S1 R XL = ωL

VMsin(wt+θ)XC = 1/ωC

Equation 6.1: RLC Current Response.

where: Irms = rms value of the currentVrms = rms value of the source voltageR = Resistance of the resistor, in ohmsL = Inductance of the inductor,

in HenriesC = Capacitance of the capacitor,

in Faradsω = Frequency of the system, in radians

per second

Irms =Vrms

R2 + (ωL – 1/ωC)2

steady-state response. The steady-state responsecontinues as long as the circuit is connected tothe source. When there is no trapped voltage onthe capacitor and no current in the inductor, thepoint on the source voltage wave at which switchS1 is closed (closing angle θ) determines if thereis a transient response and the initial magnitudeof that response. Just two closing angles do notproduce a transient response (occurring, of course,at the zero crossings).With linear parameters in the circuit, only one

steady-state response is possible, and it is inde-pendent of the closing angle and initial condi-tions at switch closure, such as capacitor voltageand inductor current. In steady-state conditions,after the transient response subsides, the currentand the voltages vary sinusoidally with time atthe same frequency as the source voltage.

Equation 6.2: Resonant Frequency.

where: ω0 = Resonant frequency, in radiansper second

L = Inductance of the inductor, in HenriesC = Capacitance of the capacitor,

in Farads

ω0 = radians/second1LC

Equation 6.3: Resonant Voltage.

where: VL = Voltage across the inductorand capacitor at resonance

L = Inductance of the inductor,in Henries

C = Capacitance of the capacitor,in Farads

R = Resistance of the resistor, in ohmsVrms = rms value of the source voltage

VL = VrmsR

LC

244 – Sect ion 6

resonance are equal to each other, the valuegiven by Equation 6.3.From Equation 6.3 it can be seen that the

voltage across the inductor and capacitor at res-onance in a series RLC circuit can be greaterthan the source voltage. If there were no resis-tance in the circuit, the capacitor and inductorvoltages would be infinite at the resonant fre-quency, but the resistance prevents this. In addi-tion, when there is resistance in the circuit, thevoltage across the inductor has its maximum at afrequency that is somewhat above the resonantfrequency, and the capacitor voltage has itsmaximum at a frequency that is slightly belowthe resonant frequency.In the linear circuit of Figure 6.2, the initial

conditions and the closing angle have no effecton the steady-state response, including whetherresonance does or does not occur. But if the in-ductor is nonlinear, because of the presence ofan iron core, the initial conditions and closingangle do affect the probability of resonance oc-curring. The resulting response in circuits withiron core inductors is called ferroresonance.

FERRORESONANCE IN THE NONLINEARINDUCTIVE CAPACITIVE CIRCUITWhen the inductor in the series RLC circuit ofFigure 6.2 is nonlinear and the circuit is ener-gized by closing switch S1, there is both a tran-sient response and a steady-state response. Thetransient response decays to zero, leaving justthe steady-state response, but the time for this tohappen with the nonlinear circuit frequently ismuch greater than in a linear circuit. Generally,two steady-state responses are possible in a sim-ple single-phase circuit with one nonlinearity,with the response determined by the closingangle and the initial conditions. However, theprobability of the two possible steady-state re-sponses is not the same or easily definable.Simple equations can be written and solved

for both the transient and steady-state responsesof the linear RLC circuit when energized from asinusoidal voltage source. For example, seeEquation 6.1 for the steady-state current. How-ever, when the inductance is nonlinear, theequations describing the circuit do not have asimple solution. Most studies of ferroresonancein power systems have been performed with ei-

ther full-scale testing, transient network analyzer(TNA) studies, or digital transient programs.Graphical techniques give an approximate solu-tion for the fundamental frequency componentof the response of the ferroresonant circuit, giv-ing some insight into the phenomenon (Ruden-berg, 1970, Chapter 48). Graphical techniquesalso show that two steady-state solutions arepossible for many ferroresonant circuits.The two steady-state responses in the single-

phase ferroresonant circuit are called the nor-mal mode and the ferroresonant mode (Feldmanand Hopkin, 1974). The ferroresonant mode ischaracterized by substantial saturation of thenonlinear inductor, high capacitor voltages, andrelatively high currents. When the steady-stateferroresonant mode occurs, the current and volt-age waveforms in the circuit are periodic butnot sinusoidal like the source voltage. Also, thepeak values of the inductor and capacitor volt-ages can be higher than the peak value of thesource voltage, just as in a linear circuit that is inresonance. Ferroresonant voltage waveshapescan be classified into three types of repetitivepatterns or modes. Three steady-state ferroreso-nant modes are, thus, possible (Germany, Mas-tero, and Vroman, 1974):

1. Fundamental,2. Subharmonic, and3. Higher harmonic.

With fundamental ferroresonance, the cur-rents and voltages are badly distorted, but thecomponent at the system frequency is the great-est. In subharmonic ferroresonance, the currentand voltage waveforms repeat at intervals oftwo or more fundamental-frequency cycles. Insubharmonic ferroresonance, the currents andvoltages contain a large component whose fre-quency is less than the frequency of the supplysystem. And with higher harmonic ferroreso-nance, the response quantities include a largecomponent whose frequency is higher than thatof the supply voltage. All three of these re-sponses have been observed during ferroreso-nance in cable-fed five-legged core, grounded-wye/grounded-wye transformers used on thesystems of RUS borrowers (Smith, Swanson, andBorst, 1975).

6


Relatively, the normal mode is characterizedby lower values of flux, current, and voltagethan occur in the ferroresonant mode. In addi-tion, with sinusoidal voltages applied, the re-sponses in the normal mode are more or lesssinusoidal.The final ferroresonant mode that has been

observed in some nonlinear circuits is one inwhich the responses are nonperiodic. That is, asteady-state response never develops. Thismode can occur in distribution systems duringferroresonance.When both the ferroresonant mode and nor-

mal mode responses are possible in circuits asin Figure 6.2 and there is no trapped charge onthe capacitor or flux in the nonlinear inductor,the point on the voltage wave at switch closingdetermines the response mode. A range of clos-ing angles give the ferroresonant mode responseand a range of closing angles give the normalmode response.

6

FIGURE 6.3: Cable-Fed Three-Phase Transformer Susceptible toFerroresonance.

Ferroresonance in distribution circuits can occurif a capacitor is placed in series with a nonlinearinductor. This condition is present when one ortwo phases of the primary line are open andthere are unloaded transformers downstreamfrom the open conductor. The capacitance canbe either upstream or downstream of the trans-former as long as both are downstream from theopen-phase point.

SWITCHING OPERATIONS PRODUCINGFERRORESONANCE IN THREE-PHASEDISTRIBUTION SYSTEMSFigure 6.3 shows a typical situation in which fer-roresonance can occur. One three-phase trans-former is fed through a cable circuit from anoverhead line, or from a pad-mounted switchingenclosure on an underground feeder. The trans-former primary windings are connected in delta,and load is not connected to the secondary dur-ing switching. The fuses providing fault protec-tion to the transformer and cable circuit are lo-cated at the cable riser pole or switching enclo-sure, whatever the situation may be. A perma-nent connection is made between the trans-former primary terminals and the cable circuit.When the unloaded three-phase transformer

and cable circuit, as in Figure 6.3, are energizedor de-energized with single-pole switches, andjust one or two switches are closed, a series LCcircuit, similar to that in Figure 6.2, is estab-lished, where the inductance is nonlinear. Thecapacitance is from the primary cable on theopen phase(s), and the nonlinear inductance isdue to the transformer exciting impedance(s). Ifthe values of L and C are in a specific range, fer-roresonance can occur, producing overvoltagesfrom both phase-to-phase and phase-to-groundon the open phases. In Figure 6.3, only thephase A switch is closed, so overvoltages canappear on phases B and C. These overvoltagescan persist as long as one or two primary phasesremain open. After all three phases are closed oropened to eliminate the single-phase condition,ferroresonance is not possible.When ferroresonance occurs, the transformer

may be very noisy because of magnetostriction inthe core. The sound emitted by the transformerfrequently is described as rattling, whining, or

Shielded Cable Circuit Pad-Mounted Transformer

Cable Capacitance

NeutralConductor

MGN

Feeder(OverheadorUnderground)

Cable Shield andConcentric Neutral

NoLoad

X1

X2X3

H3

φA

φC

φB

H2

H1

Riser Pole orSwitching Enclosure

Surge Arresters

Fused Switches

246 – Sect ion 6

loud humming. However,when low-level overvoltagesoccur across the transformerwindings during ferroreso-nance, or the voltages areless than rated, the trans-formers may not emit anyunusual noises.If the overvoltages do not

cause an insulation failure orshort circuit, the currents usu-ally will not activate overcurrent protective de-vices. Consequently, the overvoltages on theopen phases persist until all three phases are ei-ther connected to, or disconnected from, thesource. However, if the overvoltages cause thefailure of cable insulation, transformer insula-tion, or surge arresters on the open phases, thecurrents may operate overcurrent devices. If acable insulation failure occurred on open phasesB or C in Figure 6.3 when just the phase A fusedswitch was closed, the fault current would notblow the fuse in phase A. The operator at theswitch location might not be aware of the insu-lation failure. But, when the fused switch in thefaulted phase is subsequently closed, high cur-rent blows the fuse in the faulted phase.When the transformer primary windings are

ungrounded as in Figure 6.3, and the cable cir-cuit is a specified length, a defined switchingoperation may produce ferroresonant overvolt-ages some of the time and, at other times, over-voltages will not occur. That is, there is a finiteprobability that ferroresonant overvoltages willoccur when the single-pole switches energize orde-energize the circuit and transformer (Young,Schmid, and Fergestad, 1968). Factors affectingthe probability are the point on the voltagewave at which the switch is operated, the resid-ual flux in the core of the transformer, the initialcharge on the cable capacitance at the time ofswitching, the cable circuit length, the size ofthe transformer, and the switching sequence.The ferroresonant overvoltage probabilities re-ported by Young, Schmid, and Fergestad (1968)are the probabilities of obtaining the ferroreso-nant mode rather than the normal mode.Earlier investigations (Smith, Swanson, and

Borst, 1975) and more recent investigations

(Walling, 1992) with groundedwye-wye transformers on five-legged cores have shown that,when sufficient capacitance ispresent to create ferroreso-nance, the overvoltage waspresent in virtually everyswitching event. From case tocase, the maximum overvolt-age magnitudes varied withina range.

The preceding discussion assumed that loadwas not connected to the secondary side of thetransformer in Figure 6.3. If sufficient resistiveload (reasonably balanced) is connected to thesecondary, ferroresonant overvoltages will notoccur. However, most system operators will notintentionally switch a cable circuit and connectedtransformer with consumer load connected tothe secondary because doing so makes a single-phase condition that may cause harmful over-voltages if insufficient load is connected.

EQUIPMENT AFFECTED BYFERRORESONANT OVERVOLTAGESThe overvoltages produced by ferroresonancecan cause insulation in major equipment to fail.As early as 1954, the literature mentioned thefailure of reclosers and surge arresters in 24.9-kVrural systems from higher than normal 60-Hzovervoltages (Crann and Flickinger, 1954). Whencable-fed transformers are energized or de-ener-gized by switching from a riser pole (as in Fig-ure 6.3), transformer insulation failures arenumerous, especially in the early days of under-ground distribution when some pad-mountedthree-phase distribution transformers employedthe T-T winding connections. Tests with T-Tcable-fed transformers produced transient peakvoltages as high as nine times normal peak volt-age during ferroresonance (Young, Schmid, andFergestad, 1968).Other components damaged by ferroresonant

overvoltages are cables and elbow connectors.Overvoltages have caused corona in separableinsulated connectors used in 34.5-kV under-ground systems (Locke, 1978).Surge arresters applied on the distribution

system are either gapped SiC arresters, gapless

6Ferroresonance is

not a high-current

phenomenon, but

high overvoltages

may be present.


6

FIGURE 6.4: Conductor Spacings for an Overhead Line on anEight-Foot Crossarm.

FIGURE 6.5: Equivalent Capacitance Network for an OverheadMultigrounded Neutral Line.

A

B

49”

A = 300”B = 317”C = 300”N = 267”

88”

N

φB

φCφA

CAB CBC

CAC

CAG CBG CCG

Ground

Conductor Heights Above Ground

C of Pole

C

52”

47” 47”

58”

L

MOV units, or gapped MOV units. In general, agapped arrester of a given duty cycle voltagerating can withstand a higher ferroresonant over-voltage than a gapless arrester can, provided thepeak voltage does not exceed the gap sparkovervoltage. The effect of ferroresonant overvoltageson gapless MOV arresters is much less thanwould be presumed by examining the standardtemporary overvoltage (TOV) curves (Walling etal., 1992). The standard TOV curves are devel-oped using stiff 60-Hz sources, but the ferroreso-nant circuit is weak compared to the load im-posed by the MOV arrester in its conductive state.This means that the arrester can hold down thevoltage, usually without drawing a large amountof current. However, depending on the heattransfer characteristics of a given MOV arresterdesign, the arrester may eventually overheat.

IMPACT OF CIRCUIT CONSTRUCTIONOne of the parameters that determines if ferrores-onance occurs with single-pole switching of acircuit with an unloaded transformer is the circuitcapacitance. The equivalent capacitances of over-head lines are much less, by at least a factor often, than the phase-to-ground capacitance of anunderground distribution cable of equal length.Because of the higher capacitance, ferroresonanceis more likely in underground systems than inoverhead systems.

Circuit and

transformer capaci-

tances are important

in ferroresonance

equations.

Capacitances of Overhead LinesAn overhead line, consisting of three phase con-ductors and a multigrounded neutral conductor,as shown in Figure 6.4, is represented by sixequivalent capacitors as shown in Figure 6.5.There is an equivalent capacitance between eachpair of phase conductors and from each phaseconductor to ground. The neutral conductor does

248 – Sect ion 6

For symmetrical three-phase distribution lines,the phase-to-phase equivalent capacitances areabout 0.002 microfarads per mile, and the phase-to-ground capacitances are about 0.010 micro-farads per mile (Hopkinson, 1965). These areeasy-to-remember, rule-of-thumb values. For aline with 4/0 ACSR phase conductors and a 1/0ACSR neutral conductor, with the conductorheights and spacings in Figure 6.4, values for theequivalent capacitances are given in Table 6.1.The three phase-to-ground capacitances are notequal because of the unsymmetrical conductorconfiguration. Also, the phase-to-phase capaci-tances are not the same, with the capacitancefrom A to C being the smallest as these twophase conductors are the farthest apart.

Capacitances of Cable CircuitsWith single-conductor shielded cable, all capaci-tance is from phase to ground; there is no phase-to-phase capacitance. Figure 6.6 shows a crosssection of a concentric neutral cable. The separa-tion between the two “plates” making the capac-itor—the conductor shield and the insulationshield—is the thickness of the insulation, whichis less than one-half inch. In contrast, the con-ductor separation in an overhead line is severalfeet or more, so the cable capacitance is muchlarger than any of the equivalent capacitances ofan overhead line.Although the calculation of the equivalent ca-

pacitances for the overhead line is rather involved,the calculation of the shielded cable capacitanceis straightforward. The capacitance is found withEquation 6.4. In Equation 6.4, the logarithm is tothe base 10.Tables 6.2, 6.3, 6.4, and 6.5 list the capaci-

tance of cables with nominal insulation thick-nesses of 175, 220, 260, and 345 mils in sizes upthrough 1,000 kcmil. Each table gives the con-ductor size, diameter over the insulation, the ca-pacitance for cables with HMWPE and XLPEinsulation, and the cable charging in kVA permile for a three-phase circuit operating at the in-dicated phase-to-phase voltage. For cables withEPR insulation with the same nominal diameterover the insulation and the same insulationthickness, the capacitances are approximately1.3 times those in the tables.

6

Phase-to-Ground Capacitances Phase-to-Phase Capacitances(microfarads/mile) (microfarads/mile)

CAG = 0.0090 CAB = 0.0033

CBG = 0.0081 CBC = 0.0032

CCG = 0.0092 CAC = 0.0016

TABLE 6.1: Values for Equivalent Capacitances of an Overhead LineWith 4/0 ACSR Phase Conductors and a 1/0 ACSR Neutral Conductor.

FIGURE 6.6: Cross Section of a Multiwire Concentric Neutral Cable.

Insulation(220 Mils)

InsulationShield

PhaseConductor

ConductorShield

Neutral Wire

D d

Equation 6.4: Shielded Cable Capacitance.

where: C = Capacitance, in microfarads/mileD = Diameter over the insulation,

in inchesd = Diameter over the conductor shield,

in inchesK = Dielectric constant of the insulation

(For HMWPE and XLPE insulation, Kis about 2.3. For EPR insulation, K isabout 3.0.)

C =0.03886 Klog D/d

µFarads/mile

not appear in this representation because, capaci-tively, it is at the same potential as the ground.


6Conductor Size Nominal O.D. of Insulation Capacitance Three-Phase Charging(AWG or kcmil) (inches) (µFarads/mile) @ 12.47 kV (kVAC/mile)

2 0.655 0.269 15.8

1 0.690 0.291 17.0

1/0 0.725 0.312 18.3

2/0 0.765 0.336 19.7

3/0 0.855 0.391 22.9

4/0 0.915 0.427 25.0

250 0.965 0.457 26.8

300 1.020 0.490 28.7

350 1.065 0.517 30.3

400 1.110 0.543 31.9

500 1.195 0.594 34.8

600 1.275 0.641 37.6

750 1.375 0.701 41.1

1,000 1.520 0.786 46.1

* Dielectric constant of 2.3. For EPR cables with same nominal O.D., multiply capacitance and charging values in table by 1.3.Note. 175 mil insulation no longer allowed by RUS

TABLE 6.2: Representative Capacitance and Three-Phase Charging for XLPE Insulated CablesWith 175 Mils Insulation.*

Conductor Size Nominal O.D. of Insulation Capacitance Three-Phase Charging(AWG or kcmil) (inches) (µFarads/mile) @ 12.47 kV (kVAC/mile)

2 0.745 0.230 13.5

1 0.780 0.248 14.5

1/0 0.810 0.263 15.4

2/0 0.850 0.282 16.6

3/0 0.940 0.326 19.1

4/0 1.005 0.357 21.0

250 1.050 0.379 22.2

300 1.105 0.405 23.8

350 1.155 0.429 25.2

400 1.200 0.451 26.4

500 1.280 0.489 28.6

600 1.360 0.527 30.9

750 1.465 0.576 33.8

1,000 1.610 0.645 37.8

* Dielectric constant of 2.3. For EPR cables with same nominal O.D., multiply capacitance and charging values in table by 1.3.

TABLE 6.3: Representative Capacitance and Three-Phase Charging or XLPE Insulated CablesWith 220 Mils Insulation.*

250 – Sect ion 6

6Conductor Size Nominal O.D. of Insulation Capacitance Three-Phase Charging(AWG or kcmil) (inches) (µFarads/mile) @ 24.94 kV (kVAC/mile)

1 0.902 0.240 28.0

1/0 0.942 0.256 30.0

2/0 0.986 0.275 32.1

3/0 1.036 0.295 34.6

4/0 1.092 0.318 37.3

250 1.158 0.345 40.4

300 1.210 0.366 42.9

350 1.261 0.387 45.3

400 1.306 0.405 47.4

500 1.389 0.439 51.4

600 1.443 0.461 53.9

750 1.578 0.515 60.3

1,000 1.767 0.590 69.1



Conductor Size Nominal O.D. of Capacitance Three-Phase Charging Three-Phase Charging(AWG or kcmil) Insulation (inches) (µFarads/mile) @ 24.94 kV (kVAC/mile) @ 34.5 kV (kVAC/mile)

1/0 1.070 0.199 46.6 89.3

2/0 1.110 0.212 49.7 95.1

3/0 1.200 0.241 56.4 108.1

4/0 1.265 0.261 61.2 117.1

250 1.310 0.275 64.5 123.4

300 1.365 0.292 68.5 131.0

350 1.415 0.308 72.2 138.2

400 1.460 0.322 75.4 144.5

500 1.540 0.346 81.2 155.3

600 1.620 0.371 87.0 166.5

750 1.720 0.401 94.1 179.9

1,000 1.870 0.447 104.8 200.6



The capacitance values in the tables assumethat the diameter over the conductor shield, d,is the diameter over the insulation, D, minustwice the insulation thickness. The diameterover the insulation of a given size cable will

vary somewhat from manufacturer to manufac-turer, with the values in the second columntaken from one manufacturer’s handbook. Cablesize has a major effect on capacitance and, con-sequently, the likelihood of ferroresonance. The


capacitance values in the tables are used in ap-plication criteria for calculating the maximumcable length that can be switched without ex-ceeding 1.25-pu ferroresonant overvoltages.

Capacitance of Capacitor BanksCapacitor banks on a three-phase primary circuitbeing switched with a transformer may causeferroresonance because the capacitor acts like along cable circuit. Table 6.6 gives the capaci-tances of three-phase grounded-wye capacitorbanks installed in 12.47- and 24.9-kV systems.The capacitance values are based on capacitorsrated either 7.2 or 14.4 kV, with the capacitancecalculated with the assumption that the capaci-tor may deliver up to 115 percent of nominalkVAR at rated voltage. Even the smallest capaci-tor banks on a three-phase circuit look like atleast a mile of shielded cable.

Capacitance of Transformer WindingsTransformer windings have an inherent capaci-tance to ground. This capacitance adds to thatprovided by underground cables, overhead lines,or capacitor banks and it contributes to creatinga ferroresonant circuit. For a given transformer,a maximum capacitance to ground can be leftconnected to an open phase during single-phaseswitching without risking excessive ferroreso-nant overvoltage. The transformer capacitance,thus, directly reduces the allowable amount ofcapacitance that can be provided by the con-nected cable, overhead line, or capacitor bank.In some cases, the transformer capacitance

alone is sufficient to create ferroresonance. This

6Nominal Three-Phase Capacitance in Microfarads

Rating (kVA) 12.47 kV System 24.9 kV System

150 2.94 0.75

300 5.88 1.53

450 8.83 2.21

600 11.77 2.94

900 17.65 4.41

* Capacitance values based on 115 percent of nominal kVA rating.

TABLE 6.6: Phase-to-Ground Capacitance of Three-Phase Grounded-Wye Capacitor Banks.*

is particularly true of banks with ungroundedprimaries (e.g., floating wye, delta, or opendelta). It is also true of grounded-wye/grounded-wye pad-mounted transformers using five-leggedcores at 24.9 and 34.5 kV.While there are many inherent capacitances

internal to a transformer, the relevance of eachdepends on the primary winding connection.For a grounded-wye primary, the net capaci-tance between primary winding layers is the ma-jor contributor to phase-ground capacitance intransformers with the primary winding woundoutside of the secondary (SP construction). Mi-nor contributions are made by the capacitancebetween the outer primary winding layer to thecore and tank. In transformers with the secondarywound on both the inside and the outside of theprimary (SPS construction), the capacitance be-tween the outer layer of the primary windingand the first layer of the outer half of the sec-ondary winding is also a major contributor. Itshould be noted that there is no simple meansto measure the equivalent phase-to-ground ca-pacitance of a grounded-wye winding and man-ufacturers’ design data are needed to calculatethis parameter. The equivalent phase-to-groundwinding capacitances of a number of grounded-wye pad-mounted transformers have been calcu-lated; the average trend versus rated line-to-lineprimary winding voltage (in kV) and rated kVAhas been reduced to the empirical calculation inEquation 6.5 (Walling, 1992).

Equation 6.5

CXFMR =0.000469 × (kVA)0.4

(kVA)0.25

For transformers with ungrounded primaryconnections (e.g., floating wye, delta, or open-delta), the winding capacitances contributing toferroresonance are not the same as just describedfor grounded-wye primaries and the empiricalequation does not necessarily apply. The layer-to-layer capacitance does not contribute to thephase-to-ground capacitance, for example. In atransformer with SPS construction, the capaci-tance between both (a) the outer layer of theprimary and the first layer of the outer secondary

252 – Sect ion 6

and (b) the innermost primary winding layerand the last layer of the inner secondary add tothe phase-to-ground capacitance and, thus, havean effect on the likelihood of ferroresonance.

Because the winding in transformers with un-grounded primaries does not shunt the phase-to-ground capacitances, the total capacitancecan be easily measured.

6

FerroresonanceWhen Switchingat the PrimaryTerminals ofOverhead andUndergroundTransformerBanks

Ferroresonance can occur with certain trans-former connections and switching operations inoverhead distribution systems when the switch-ing is done at the primary terminals of the trans-former bank (two or three single-phase trans-formers). Similarly, ferroresonance can occur inunderground systems with the same transformerconnections when the switching is done at theprimary terminals of the bank. The capacitanceforming the ferroresonant circuit in these casesis the inherent capacitance of the transformerwindings as discussed in the previous subsection.Before widespread loss evaluation, ferroreso-

nant overvoltages seldom occurred on five- and15-kV class overhead distribution systems whenthe switching was done at the primary terminalsof the bank (Stoelting, 1966). Ferroresonance didoccur during this era in 24.9- and 34.5-kV over-head systems when energizing or de-energizing—with single-pole switches located at the primaryterminals—small transformer banks connectedfloating-wye on the primary and delta on thesecondary. Recent tests performed on a bank ofmodern low-loss 13.8-kV (line-to-line) trans-formers, with the primaries connected in float-ing-wye, have shown very se-vere ferroresonant overvolt-ages. Thus, it is no longer safeto consider 15-kV class trans-formers immune to ferroreso-nance when switching at theterminals of banks with un-grounded primary windings.This subsection considers

situations in which the switch-ing is done at the primary ter-minals of transformer banksmade from single-phase trans-formers when no primary cir-cuits are connected to theopen terminals. The lessons learned whenswitching transformer banks in overhead systemsapply equally well to underground systems.

The primary windings of single-phase distribu-tion transformers in banks in the overhead sys-tem, and in the underground system, may or maynot be grounded by connection to the multi-grounded neutral conductor of the primary system.

GROUNDED PRIMARY WINDINGSWhen the primary windings of the single-phasetransformers in the bank are grounded, eitherthe grounded-wye or the open-wye connectionis employed. With grounded primary windings,whether the secondary is in wye or delta, ferrores-onance is impossible during single-pole switch-ing at the primary terminals of the transformerbank, at any primary voltage level, whether loadis or is not connected to the secondary side ofthe bank. But if power factor capacitors, con-nected in either delta or floating-wye, are ap-plied on the secondary side of the otherwise un-loaded bank, ferroresonance is possible.When opening and closing switches at the

primary terminals of transformer banks (withtwo or three single-phase transformers) with thegrounded-wye or the open-wye primary wind-ings, whether the primary circuits are overhead

or underground, disconnectsecondary capacitors beforethe switching is performed ifthe capacitors are connectedin delta or ungrounded wye.

UNGROUNDED PRIMARYWINDINGSIn the past, when the primarywindings of the single-phasetransformers in the bank werenot grounded in 12.47-kV andlower voltage systems, andload was not connected to thesecondary system, ferroreso-

nance and harmful overvoltages generally didnot occur when single-pole switching was per-formed at the primary terminals (Ferguson,

All switching of

transformers or

transformer banks

with ungrounded

primary connections

should be considered

as having the potential

for ferroresonance.


1968). One can no longerassume this to always be truewhen more modern loss-eval-uated distribution transformersare used. Connections inwhich the windings areungrounded are delta, open-delta, and floating-wye. If loadis connected to the secondarywhen the switching is per-formed at the primary termi-nals, and the load isreasonably balanced, overvoltages also will notoccur.When 24.9-kV and higher voltages were adopt-

ed for overhead distribution systems, ferroreso-nance did occur when switching at the primaryterminals of small floating-wye/delta transformerbanks without load on the secondary. Tests bythe RUS showed that phase-to-ground overvolt-ages as high as 2.5 pu occurred on the open pri-mary phase when switching banks made from10- and 25-kVA transformers in 24.9-kV systems(Crann and Flickinger, 1954). Full-scale tests byone utility with three 15-kVA units in a 34.5-kVfloating-wye/delta bank resulted in phase-to-ground overvoltages of five per unit (Shultz,1964). Tests by another utility with three 50-kVA

6

FIGURE 6.7: Floating-Wye/Delta Transformer Bank with Fused Cutoutsat Primary Terminals.

transformers in a 34.5-kVsystem resulted in steady-statevoltages to ground on theopen phases of about 2.2 timesnormal (Pennsylvania ElectricCompany, 1964). More recentfull-scale tests of modern low-loss 25-kVA transformers withsilicon-steel cores, banked in afloating-wye/delta connectionat 25 kV, yielded peak over-voltages in excess of four per

unit (Walling, 1991). Whether the primary systemis overhead or underground, overvoltages canoccur during single-pole switching at the primaryterminals of small floating-wye/delta banks in 15-,25-, and 35-kV class systems.The neutral point of the primary windings

should be temporarily connected to the neutralconductor of the primary system to preventovervoltages during the single-pole switching atthe primary terminals of the smaller floating-wye/delta banks. This connection is representedin Figure 6.7 by the closing of switch SW1 in theconnection between the neutral of the bank andthe neutral conductor of the primary system. Fer-roresonance occurs during single-phase condi-tions, and it doesn’t matter if the cutouts arebeing closed to energize the bank or opened tode-energize the bank. Thus, the switch in theneutral is closed before the three fused cutoutsare closed to energize the bank, and the neutralswitch is also closed before the three fusedcutouts are opened to de-energize the bank.After the cutouts are closed to energize the

bank, neutral switch SW1 must be opened. If theswitch remains closed, the transformer bank actsas a ground source for the primary feeder undernormal conditions, tending to balance the loadon the three primary phases. Furthermore, if anopen phase occurred on the primary feederbetween the substation and the location of thegrounded-wye/delta transformer bank, the bankwould supply the load on the open primaryphase beyond the open point. This conditionmay produce loadings where the fuses for thegrounded-wye bank do not provide overloadprotection. The transformers can fail thermallybefore the fused cutouts operate to relieve the

Temporary

neutral-point grounds

installed for switching

must always be

removed for normal

operation.

Multigrounded Neutral Primary Feeder

Neutral Conductor

Fused Cutouts

ServiceSwitch

Pole-TopTransformer Bank

Surge Arresters

φA

φB

φC

φA φB φC

SW1

254 – Sect ion 6

overload. Of even more importance is the factthat the backfeed condition from the grounded-wye bank will be hazardous to personnel work-ing on the lines.Temporarily grounding the neutral of the float-

ing-wye/delta bank prevents ferroresonanceduring planned single-pole switching. Thisgrounding will not prevent ferroresonance if aphase opens in the primary supply lines whenthe bank and lines are unloaded or lightlyloaded, as the neutral will not be grounded.The floating-wye/delta bank is employed to

supply three- and four-wire delta secondaries.An alternative to temporarily grounding the neu-tral of the floating-wye/delta bank, to preventferroresonance during switching at the primaryterminals, is to select transformer connectionsthat can be grounded yet do not act as a groundsource for the primary system. The open-wye/open-delta transformer bank satisfies these crite-ria for service to three- and four-wire delta loadsin 25- and 35-kV class systems. However, al-though this connection prevents ferroresonancefor single-pole switching, it may create highervoltage unbalance in the secondary system than

the floating-wye/delta bank; if the two trans-formers in the open-wye/open-delta bank areinadvertently connected to the same primaryphase, the secondary phase-to-phase voltageacross the missing leg will be two times normal.As shown in Figure 6.7, if load is connected

to the secondary of the floating-wye/delta bankduring switching and the load is reasonably bal-anced, overvoltages will not occur from phaseto neutral on the bank side of the open cutoutson the primary side regardless of primary systemvoltage. However, if the load connected to thesecondary is badly unbalanced or connectedacross just one phase, the phase-to-neutral volt-age at the open primary terminal can be as highas 2.65 pu. This is not due to a nonlinear reso-nance, but to voltage feedback through the sec-ondary load (Gasal, 1986). Such occurrences havecaused the failure of gapped SiC and MOV surgearresters connected to the terminals of the bank.If a floating-wye/delta bank is to be switched atits primary terminals with load connected to thesecondary, regardless of primary voltage, theload should be reasonably balanced.

6

Ferroresonancewith Cable-Fed,Three-PhaseTransformerswith Delta orUngrounded-WyeConnectedPrimary Windings

When 15-kV class voltages were selected foroverhead multigrounded neutral systems, theungrounded-wye or delta connections frequentlywere employed for primary windings in distribu-tion transformer banks and in three-phase trans-formers. These connections had been usedsuccessfully in lower voltage primary systems. Inthe 1950s and ’60s, when pad-mounted and sub-mersible transformers were first produced forUD systems, many of them also had the delta orungrounded-wye primary windings that hadbeen applied successfully in overhead systems.Early UD systems often consisted of a three-

phase transformer fed through a cable circuitfrom an overhead line, with fused cutouts at theriser pole to energize and de-energize the cableand connected transformer. This arrangement isshown in Figure 6.8. During single-pole switch-ing at the riser pole, transformers with un-grounded primary windings sometimes failed, oremitted unusual noises, and externally gappedsurge arresters “spat” across the external gap.

Sometimes the arresters failed. The cause ofthese problems was ferroresonance.For the system configuration of Figure 6.8,

Figure 6.9 shows the measured voltage wave-forms and current into terminal H2 of the trans-former when the cable and transformer areenergized with single-pole switches. Thesewaveforms are from tests on a 150-kVA delta/grounded-wye transformer bank fed through acable circuit with a phase-to-ground capacitanceof 0.1 microfarads per phase. Terminal H1 is en-ergized first by closing the switch in phase A,followed 12 cycles later by closing the switch inphase B to energize terminal H2. During this 12-cycle interval, the voltages from H2 to groundand H3 to ground are as high as three per unit,and the transient response has not fully de-cayed. From the waveforms, the ferroresonantmode response in the first 12 cycles is at funda-mental frequency. After the switch in phase B isclosed, the transient voltage from terminal H3 toground approaches four per unit. Although not


The factors with the greatest effect on thelikelihood of overvoltages on the open phasesduring the switching of a cable circuit and aconnected transformer are the following:

• Transformer kVA size (kVAT in Figure 6.8),• Primary voltage level (kV in Figure 6.8),• Phase-to-ground capacitance (cable length)of the circuit being switched with the trans-former, and

• Transformer exciting current at rated voltage(IE% in Figure 6.8).

Measures that can limit the voltage on theopen phases to 1.25 pu are as follows:

• Grounding, through a resistor, the neutral of thewye-connected primary windings (secondaryconnected in delta). This approach has notbeen widely accepted because of cost, com-plexity, and the fact that it cannot be usedwith transformers having the delta-connectedprimary winding.

• Connecting resistive load to the secondaryside of the three-phase transformer duringsingle-pole switching. Most users rejectedreliance on secondary load as they did notwant to intentionally single-phase theircustomers. Also, if the load was not largeenough, high overvoltages could occur anddamage the customer’s load.

6

FIGURE 6.8: Three-Phase Cable-Fed Transformer with a Delta-Connected Primary Winding.

FIGURE 6.9: Voltage and Current Waveforms During Ferroresonancewith a 150-kVA Delta/Grounded-Wye Bank.

Shielded Cable Circuit Pad-Mounted Transformer

Cable Capacitance

TransformerSwitch

NoLoad

kVATkVIE%

X1

X2

X3H3

XC

XC

XC

φA

φC

φB

H2

L∆

H1

H3V

H2V

H1V

H2I

3 pu 2 pu

4 pu

1 pu

H1 Energized

H2 Energized

Surge Arresters

Fused Cutouts

shown, closing the switch in phase C terminatesferroresonance and eliminates the overvoltages.Other full-scale tests show that, when cable-fedtransformers have the delta or ungrounded-wyeprimary windings, steady-state overvoltages ashigh as four per unit can occur during ferroreso-nance (Young, Schmid, and Fergestad, 1968).

256 – Sect ion 6

• Applying three-pole switches at the riser pole.Many users rejected three-pole switchesbecause of their high cost in comparison tofused cutouts.

• Performing the single-pole switching at theprimary terminals of the three-phase trans-former, with no cable connected to thede-energized primary terminals. The de-ener-gized primary terminals of the transformer arethose that are not connected directly to thesource system, but can have voltage on thembecause of coupling through the transformer,or because of load on the secondary side ofthe transformer.

• Limiting the length of the cable circuit beingswitched with the transformer.

A 1.25-pu voltage level is used for establish-ing ferroresonance criteria for the maximum ca-ble length that can be switched with a connect-ed transformer, as temporary overvoltages at thislevel should not be harmful to the system orequipment. Overvoltages of this and highermagnitudes occur during ground faults. GappedSiC arresters can withstand 1.25-pu temporaryovervoltages without trouble. Distribution classand riser pole MOV surge arresters can with-stand temporary overvoltages of 1.25 times sys-tem line-to-neutral voltage (about 1.0 times ar-rester duty-cycle voltage rating) for one to twohours or more, depending on the specific designand manufacturer. The 1.25-pu voltage level issignificantly below the applied voltage test givento transformers with ungrounded primary wind-ings and the induced voltage test given to trans-formers with a grounded primary winding.Similarly, the insulation of other equipment such

as cables, cable terminators, splices, separableconnectors, and fused cutouts can withstand the1.25-pu line-to-neutral voltages from ferroreso-nance, and commonly occurring ground faults.

MAXIMUM ALLOWED CABLE LENGTHS TOLIMIT OPEN-PHASE VOLTAGES TO 1.25 PUThe maximum cable lengths with a connectedtransformer that can be switched with single-pole switches so that voltages do not exceed1.25 pu were found using either full-scale tests(Young, Schmid, and Fergestad, 1968) or TNA

simulations. Normally, the transformer is at theend of the cable circuit as in Figure 6.8, but itmay be connected at any point along the cable.The results from TNA simulations are more con-servative than those obtained from the full-scaletests performed in the same era. Therefore, theconventional criteria for maximum allowedcable lengths have been based on the TNA stud-ies for transformers with both the delta and un-grounded-wye connected primary windings(Hopkinson, 1967, 1968).The significance of no-load loss to ferroreso-

nance susceptibility was not understood at thetime the TNA work was performed because therewas good correlation between rated-voltage ex-citing current and ferroresonance susceptibility.More recent investigations on grounded-wyetransformers indicate that exciting current atrated voltage does not accurately reflect ferro-resonance susceptibility, but no-load loss does(Walling et al., 1992). Computer simulation ofdelta-wye transformers tends to indicate that thesame is true for transformers with ungroundedprimaries (Walling, 1992). Full-scale testing withmodern transformers has yet to be performed todetermine if the previous approach to ferroreso-nance guidelines, based on rated exciting cur-rent, is valid for low-loss units. In the absence ofa verified new approach, the conventional ap-proach based on the TNA investigations of thelate 1960s is used in this subsection.When the phase-to-ground voltages on the open

phases are limited to 1.25 pu, the voltage acrossthe windings, either delta- or wye-connected, willbe less than 1.1 times winding rated voltage. Suchovervoltage will not damage transformers as theycan continuously withstand across their windings,at no load, 110 percent of winding rated voltage.

Application CriteriaFor a three-phase unloaded transformer with thedelta-connected primary windings fed through acable circuit (as in Figure 6.8), the voltages toground on the open phases during single-poleswitching will not exceed 1.25 pu if the inequal-ity of Equation 6.6 is satisfied.This inequality is expressed in terms of more

readily available transformer and system para-meters by the inequality of Equation 6.7.

6


depending on transformer voltage and kVA rat-ing plus the manufacturer’s design practices.From the inequality of Equation 6.7, it can be

seen that ferroresonant overvoltages above 1.25pu are more likely to occur with smaller trans-formers and longer cable circuits, and at thehigher primary voltage levels. The term involv-ing primary voltage, kV, is squared, so doublingthe primary voltage reduces the term on the leftside of the inequality by a factor of four.

6

Equation 6.6

where: XC = Phase-to-ground capacitive reactance of one phase of thecable circuit, in ohms. This capacitive reactance is identified inFigure 6.8.

XM = Equivalent exciting reactance of the transformer, in ohms. This isequal to the line-to-line rated voltage of the primary winding involts divided by the rated voltage exciting current in amperes,divided by √3.

XCXM

≥ 40

Equation 6.7

where: kVAT = Nameplate kVA rating of the three-phase transformerIE% = Exciting current of the transformer at rated voltage in percent-

age of rated currentkV = Rated phase-to-phase voltage of the transformer primary wind-

ing in kV. This is the voltage on the nameplate.CµF/M = Capacitance of the shielded single-conductor cable in micro-

farads per mile. This capacitance is found from Equation 6.4.Representative values are given in Tables 6.2, 6.3, and 6.4.

L∆ = The total length of the cable being switched with the trans-former with delta-connected primary winding. If the cable ex-tends beyond the transformer, this is the total length of thecable being switched.

kVATIE%kV2CµF/ML∆

≥ 0.286

Equation 6.8

where: CXFMR = The equivalent phase-to-ground winding capacitance of thetransformer in µF

3.5kVATIE%kV2CµF/M

CXFMR × 5,280CµF/M

–L∆max =

It should be noted that Equation 6.7 ignoresthe capacitance contribution provided by thetransformer windings. This transformer capaci-tance parameter is not readily available to utili-ties but it can be very important because it mayequal the capacitance of 50 or 100 feet of cable,

Ferroresonance is

more likely with small

transformers, higher

primary voltages, and

longer cable circuits.

When the transformer parameters and cablecapacitance are known, the maximum length(L∆max) of cable circuit that can be switched withthe transformer with the delta-connected primarywinding, so that the voltages do not exceed 1.25pu, is given by Equation 6.8. This equation in-cludes the correction for transformer winding ca-pacitance.Use of Equation 6.8 is illustrated by the fol-

lowing example and data:

kVAT = 1,500 kVAIE% = 1.0%kV = 12.47 kVCµF/M = 0.312 µF/M (for 1/0 phase conduc-

tor with 175 mils of XLPE insulationper Table 6.2)

CXFMR = 0.006 µF

Placing these values in Equation 6.8 gives thefollowing:

3.5 × 1,500 × 1.012.472 × 0.312

0.006 × 5,2800.312

–

L∆max =

= 6.7 feet

258 – Sect ion 6

This example reveals that, even with largerkVA transformers with the delta primary wind-ing, the allowed length of cable to limit theovervoltage to 1.25 pu is impractically short, 6.7feet, at 12.47 kV. If the primary voltage was 24.9kV, the winding capacitance correction wouldexceed the other term and this equation wouldyield a negative critical cable length. The voltagecould, therefore, exceed 1.25 pu if the trans-former was switched single phase, solely as aresult of internal transformer capacitances.For three-phase transformers with the un-

grounded-wye primary winding, the voltages onthe open phases during remote single-poleswitching through a shielded cable will not ex-ceed 1.25 pu if the ratio of XC to XM is greaterthan 30 (Hopkinson, 1968). From this, it is con-cluded that the maximum length of cable circuit,identified as LYmax, and connected transformerwith the floating wye-connected primary wind-ing that can be switched so that the voltages donot exceed 1.25 pu is given by Equation 6.9.

6

Equation 6.9

4.7kVATIE%kV2CµF/M

CXFMR × 5,280CµF/M

–LYmax = feet

All terms in Equation 6.9 are the same as inEquation 6.8. From the constant terms, the al-lowable cable lengths with the ungrounded-wyeprimary winding are, at most, 34 percent greaterthan those allowed with the delta primary wind-ing. However, with the ungrounded-wye pri-mary windings, the lengths that limit voltages to1.25 pu are so short that practical applicationsusually cannot be made.In light of the low loss levels and small excit-

ing currents in modern distribution transformers,there is little value in specifying maximum cablelengths for transformers with ungrounded pri-mary windings. In all cases, prudence dictatesthat these transformers be switched only at theprimary terminals. Phase-to-ground winding ca-pacitance varies with rating and also greatly withtransformer design practices. For those units inwhich unacceptable overvoltages result fromsingle-phase switching at the terminals (such as

by elbows), three-phase ganged switches mustbe provided or other means used to control theovervoltages.

SWITCHING (OPERATING) PROCEDURESTO PREVENT FERRORESONANCEIf transformers with the delta or ungrounded-wye primary windings must be used in the UDsystem, there are two options for preventing fer-roresonant overvoltages above 1.25 pu: eitheruse three-pole switches or do single-pole switch-ing at the transformer terminals. The latter is ef-fective only when the internal capacitance of thetransformer is less than the critical capacitance.This tends to be true for higher loss transformersin 15-kV class systems and with the larger trans-formers in the 25-kV class systems. It is not rec-ommended for any size transformer in 35-kVclass systems. Reasons sometimes given for therequirement of the delta or ungrounded-wye pri-mary winding connections, rather than thegrounded-wye primary connections, especiallyfor the larger three-phase distribution transform-ers, are as follows:

• To isolate the primary and secondary systemsso that the fundamental frequency componentof the unbalanced load current, the third har-monic load current, and its odd multiples (9th,15th, 21st harmonic . . .) do not flow in theneutral conductor of the primary system, and

• To isolate the primary and secondary systemsso that ground relays on the primary systemdo not see ground faults on the secondarysystem.

Single-Pole SwitchesWhen only single-pole switches are available,ferroresonant overvoltages above 1.25 pu can beprevented by switching procedures whereby un-loaded transformers and cable circuit are notswitched as a single entity. This is accomplishedby first, energizing the cable circuit with alltransformers disconnected and second, connect-ing the transformers to the energized cable cir-cuit with switching devices at the primary termi-nals of the transformer. When the transformer isconnected to the cable circuit, no cable is con-nected to the de-energized primary terminals.


This procedure is effective at voltage levels of15 kV and below, as long as the transformersare not low loss. However, at the 24.9-kV volt-age level, or in the case of low-loss transform-ers, single-pole switching at the transformer ter-minals to energize just the transformer may re-sult in high overvoltages as a result of the inter-nal capacitances of the transformer. Single-poleswitching of transformers with ungrounded pri-mary windings is not recom-mended in 34.5-kV systems.Switching at the transformer

primary terminals can be donewith load-break elbow con-nectors, load-break fusing de-vices internal to the trans-former, or switches internal tothe transformer. This is illus-trated with an example usingthe radially fed transformer inFigure 6.8.To energize the cable and connected trans-

former, do the following:

STEP 1: Open the switching devices at the trans-former, disconnecting the transformerfrom the cable.

STEP 2: Close the single-pole switches at thesource end of the cable circuit to ener-gize just the cable circuit.

STEP 3: Close the switching devices at the trans-former to energize the transformer.

If the cooperative desires to energize trans-formers from a remote location, for operatorsafety, this switching procedure is unacceptable.To de-energize the cable circuit and trans-

former, as in Figure 6.8, just the opposite proce-dure is used. First, the switching devices at thetransformer are opened, de-energizing the trans-former. Second, the single-pole switching de-vices at the source end of the cable circuit areopened to de-energize just the cable.

Three-Pole SwitchesThree-pole switching of the cable circuit andconnected transformer prevents ferroresonancefor either energizing or de-energizing opera-tions. For the three-pole switch to be effective,

the time between closing of the first pole andclosing of the third pole, referred to as polespan, must not be too long, or high overvoltageswill build up. With pole spans of one cycle (16.6milliseconds) or less, harmful overvoltages willnot develop. Similarly, the switch pole spanmust be one cycle or less on opening.A three-pole switch installed in the three-

phase transformers with the delta or un-grounded-wye primarywindings prevents overvolt-ages for switching at the pri-mary terminals to energizejust the transformer. Thisswitch is closed to energizethe transformer after the cablecircuit is energized from a re-mote location, with either sin-gle- or three-pole switches.Similarly, the three-pole switchat the transformer is opened

before the cable circuit is de-energized at theremote location.

Temporary Grounding of the NeutralIf the three-phase transformer has the un-grounded-wye primary windings with the neu-tral of the wye available external to the case,overvoltages do not occur if the neutral isgrounded during single-pole switching of thecable circuit and connected transformer, or dur-ing switching of just the transformer. When theprimary winding of the transformer is rated EYvolts, where E is the phase-to-phase rated volt-age of the primary, the neutral of the wye is notbrought outside the tank. If the primary windingis rated 3 EY/E volts, where E is the ratedphase-to-neutral voltage of the primary wind-ings, the neutral of the wye-connected primaryis brought out. If the installation is made fromthree single-phase transformers, the neutral ofthe primary windings is available.Temporary neutral grounding is effective at

any primary voltage level. The neutral pointshould be grounded only during the switching.If left permanently grounded, the transformermay be damaged thermally if single-phasing oc-curs on the primary system on the source sideof the grounded-wye/delta bank.

6

Do not do single-pole

switching of

transformers with

ungrounded primary

windings at 34.5-kV.

260 – Sect ion 6

For transformers with ungrounded primarywindings, the cable lengths that allow single-pole switching are so short that practical systemsusually cannot be operated. Single-pole switch-ing at the transformer primary terminals to ener-gize or de-energize just the transformer (withoutcable connected to the de-energized primary ter-minals) usually prevents objectionable overvolt-ages in 12.47-kV systems, but is not effective in24.9- and 34.5-kV systems or where lower losstransformers are applied. And installation ofthree-pole switching devices is expensive com-pared with installation of single-pole switchingdevices. As a result of these limitations, alterna-tive transformer designs allowing single-poleswitching without objectionable overvoltageswere sought by the utility industry.Some papers on ferroresonance written in the

1960s suggested that the grounded-wye primarywinding connections would prevent overvolt-ages during single-pole switching of a cable cir-cuit and a connected transformer. Operatingexperience and tests showed that the effective-ness of the grounded-wye primary windings inpreventing overvoltages depended on whetherthe transformer was assembled on a five-leggedcore or used triplex construction. From tests, thefollowing was learned:

• When the three-phase transformer employstriplex construction with grounded primary

6Ferroresonancewith Cable-FedThree-PhaseTransformers withGrounded-WyePrimary Windingand Five-LeggedCore

windings, and power factor capacitors con-nected in delta or ungrounded-wye are notconnected to the secondary, ferroresonanceand overvoltages will not occur for single-pole switching of the cable circuit andtransformer or for single-pole switching at theprimary terminals.

• When the transformer has a five-legged coreand grounded-wye primary windings, over-voltages can occur when a cable circuit andconnected transformer are switched with sin-gle-pole switches. In general, much longerlengths of cable and connected transformercan be switched when the transformer hasgrounded-wye primary windings rather thanungrounded primary windings withoutexceeding 1.25-pu voltage.

• When the transformer has a five-legged coreand grounded-wye primary windings, overvolt-ages can occur during single-pole switching atthe primary terminals of the lower-kVA, lower-loss transformers used in 24.9- and 34.5-kVsystems. These overvoltages occur due to theinternal capacitances of the transformer.

The performance of the five-legged coretransformer with grounded-wye connected pri-mary windings is discussed in the following sub-section. Grounded-wye primary windings areused with grounded-wye secondary windings orungrounded-wye secondary windings, depend-ing on the type of service. Delta-connected sec-ondary windings should not be used withgrounded-wye primary windings.

CORE CONFIGURATIONMost three-phase distribution transformers withgrounded-wye primary windings are constructedon a five-legged, wound-type core. Transformerswith grounded-wye primary windings cannot beconstructed on a three-legged core as commonunbalances in the primary system give severeheating in the transformer tank.Figure 6.10 illustrates the configuration of the

five-legged, wound-type core. The core assem-bly is made from four individual wound-typecores. The two inner core loops have the samemean length and the two outer core loops havethe same mean length, but the mean length of

FIGURE 6.10: Five-Legged Wound-Type Core with Grounded-WyePrimary Windings.

H1 H2 H3


an inner core loop is longer than the meanlength of an outer core loop. In Figure 6.10,only the primary winding for each phase is de-picted. The secondary winding for each phase iswound concentric to the primary winding.Disregarding the effects of transformer wind-

ing capacitances, the magnetic circuit of the five-legged core transformer in Figure 6.10 showsthat, when rated voltage is applied between theline terminal of any one winding and ground,with all other windings open circuited, voltageappears between the line terminal and groundof the open windings. Similarly, if voltages fromtwo phases of a three-phase system are appliedbetween the line terminal and ground of anytwo windings, voltage appears between the lineterminal and ground of the open winding.Tests run in the 1970s on transformers rated

12.47/7.2 kV showed that the rms value and thepeak value of the voltage from the open terminalto ground did not exceed winding rated rms andpeak voltages, respectively (Smith, Swanson,and Borst, 1975). The voltage appearing on theopen phases is not sinusoidal as is the appliedvoltage because of the nonlinear characteristicsof the core loops. Tests run more recently withlow-loss transformers rated 12.47/7.2 kV alsoshow that the rms value of the voltages fromthe open terminals to ground does not exceedwinding rated rms voltage, but the peak value isabout two percent above rated peak voltage as aresult of harmonics (Millet, Mairs, and Stuehm,1990). Thus, for practical purposes, switching atthe primary terminals of the grounded-wye pri-mary five-legged core transformers preventsovervoltages in systems with voltages of 15 kVand below.However, test results made available in the

summer of 1992 show that the five-legged coretransformer internal capacitances can react withthe magnetic circuits to produce overvoltageswhen the switching is done at the primary ter-minals of the smaller low-loss transformers usedin 24.9- and 34.5-kV systems (Walling et al.,1992). From tests on transformers applied in24.9-kV systems, the peak line-to-ground voltagewas 1.29 pu; for transformers applied in 34.5-kVsystems, the peak line-to-ground voltage was

1.47 pu. These transformers had lower loss lev-els than did the transformers used in prior testsin the early 1970s.The voltages appearing at the open-circuited

terminals demonstrate that magnetic couplingexists between the phases of the five-leggedcore transformer. This magnetic coupling be-tween phases, in conjunction with the capaci-tance to ground (neutral) of the primary cableconnected to the open phases, or the internalcapacitance of the transformer if high enough,produces a series/parallel LC circuit in whichovervoltages are possible.Most published information on the perfor-

mance of the five-legged core grounded-wye/grounded-wye transformer is based on tests andTNA simulations done in the early 1970s, beforelosses were evaluated by most utilities. The sig-nificance of the age of this information is thatthe losses of transformers on which the applica-tion criteria in this section are based are higherthan the losses of many newer transformers. Thematerial on ferroresonance with five-legged coregrounded-wye transformers in this section and,in particular, the criteria for allowed cable lengthto limit the overvoltages to 1.25 pu, is based onthe published literature (Smith, Swanson, andBorst, 1975; Millet, Mairs, and Stuehm, 1990) andpersonal experience. However, recent tests withnewer transformers having lower core lossesshow that the currently accepted application cri-teria for allowed cable lengths need to be modi-fied to take into account the lower losses. Infact, core loss is a better indicator of the criticalcapacitance than is exciting current as used inthe older guidelines (Walling et al., 1992).The maximum peak voltage during ferroreso-

nance with the five-legged core grounded-wyetransformer is 2.1 pu, based on tests in the1970s. Tests on the lower loss five-legged coregrounded-wye transformers of more recent de-sign show that the sustained voltages during fer-roresonance are as high as 2.4 pu (Walling et al.,1992). In comparison, the maximum steady-stateovervoltages possible with the delta or un-grounded-wye windings are 4 pu (Young,Schmid, and Fergestad, 1968).

6

262 – Sect ion 6

6

FIGURE 6.11: Three-Phase Cable-Fed Transformer with a Grounded-Wye Primary Winding on a Five-Legged Core.

FIGURE 6.12: Open-Phase Voltage Waveforms with Five-Legged Core,Grounded-Wye Transformers.

Shielded Cable Circuit Pad-Mounted TransformerFive-Legged Core

Cable Capacitance

TransformerSwitch

X1

X2X3H3

XC

XC

XC

φA

φC

φB H2

LGY

H1

Surge Arresters

Fused Cutouts

NoLoad

MAXIMUM ALLOWED CABLE LENGTHS TOLIMIT OPEN-PHASE VOLTAGES TO 1.25 PUFigure 6.11 shows a five-legged core transformerfed through a cable circuit. The length of thecircuit is designated as LGY. Although the trans-former is connected to the end of the cable,the system response is the same irrespective ofwhere the transformer is located along its length.The reason for this is that the voltage dropthrough the series impedance of the cable circuitis negligible during ferroresonance.The type of response and peak value of the

overvoltages on the open phases for single-poleswitching are affected to a great extent by thedistance between the switches and transformer.Roughly, when switching is performed at the

primary terminals of the five-legged core trans-former (no cable connected to the de-energizedterminals), the voltages to ground on the openphases are at a minimum. As the cable lengthbeing switched with the transformer increases,the voltage increases, reaching a maximum ofabout two to 2.5 pu. The distance at which thismaximum occurs depends primarily on the kVArating of the transformer, transformer core losslevel, primary voltage, and cable capacitance.Whether one or two phases are connected to thesource also affects the responses. Generally, fora given cable length, the overvoltages are higherwhen just one phase is open.Figure 6.12 shows examples of the steady-state,

phase-to-ground voltages on the open phasesduring single-pole switching, based on full-scaletests with 150-, 225-, and 500-kVA transformers(Smith, Swanson, and Borst, 1975). The responserepresented by the two voltage waveforms inFigure 6.12(a) is cyclical at fundamental frequencyand symmetrical, as only odd harmonics are pre-sent. In Figure 6.12(b), the voltage waveformsalso are cyclical at fundamental frequency, butthey are not symmetrical about the time axis be-cause of the presence of even harmonics. Nonhar-monic responses also occur during ferroresonancewith the five-legged core transformers, as illus-trated in Figure 6.12(c). Here the waveformnever repeats itself and there are no identifiablecyclical patterns. These responses produced themaximum voltage of 2.1 pu, and it is duringthese types of responses that the transformer

1 Cyc. at 60 Hz

__1.02 pu__1.09 pu

__.71 pu

__1.41 pu

1 Cyc. at 60 Hz

1 Cyc. at 60 Hz

1 Cyc. at 60 Hz

__1.04 pu

__.77 pu

1 Cyc. at 60 Hz 1 Cyc. at 60 Hz

__2.0 pu

1 Cyc. at 60 Hz

(a)

(b)

(c)

(d)


can be very noisy because of magnetostriction.Twenty- and 30-Hz subharmonic steady-stateresponses also occur with the five-legged coretransformer, as shown in Figure 6.12(d).Work completed in 1992 has re-examined

the ferroresonance susceptibility of groundedwye/wye transformers using a five-legged core(Walling, 1992). This investigation concluded thatcore loss is the key parameter defining the criti-cal capacitance creating ferroresonant overvolt-age. Previous guidelines using exciting currentas a basis have been generally satisfactory be-cause core losses and exciting current have his-torically correlated. New low-loss designs andwider variations in design flux density haveshown the pitfalls of exciting-current-basedguidelines. One such shortcoming, for example,is that the measured exciting current on a trans-former can be dominated by the winding capaci-tance. The older guidelines yield a longer criticalcable length for a transformer that has a highmeasured exciting current because of a high in-ternal capacitance. This internal capacitance addsto that of the cable, however, and the actual criti-cal cable length should be shorter than for that ofa transformer with a smaller exciting current thatis more inductive.

6The guidelines in this subsection are based on

more recent research. They apply to a singletransformer, without secondary load, connectedto cable circuit as shown in Figure 6.11.

Application CriteriaFor the voltage to ground to be limited to 1.25pu during single-pole switching of the cable cir-cuit and connected transformer, the inequality ofEquation 6.10 must be satisfied (Walling, 1992).From the inequality of Equation 6.10, over-

voltages above 1.25 pu are more likely to occurwith the smaller or more efficient transformers atthe higher primary voltage levels and with longercable circuits. The maximum length of cable cir-cuit, LGYmax, that can be switched with the trans-former so that the voltages do not exceed 1.25 puis given by Equation 6.11. This equation is theinequality of Equation 6.10 combined with anapproximate empirical relationship betweentransformer rating and internal capacitance andsolved for LGY.If the primary cable extends beyond the trans-

former in Figure 6.11, but does not serve anyother transformers, LGY is the total length of cablebeing switched with the unloaded transformer.Transformer no-load loss values can vary widely

for transformers of a given kVA rating. This widevariation occurs because the loss evaluation fac-tors used in transformer procurement by variousutilities vary widely, and the core losses of vari-ous manufacturers’ designs also vary, even whenbid to the same loss evaluation specification.Where possible, the actual no-load loss shouldbe used in Equation 6.11 but this is not alwaysfeasible when standard practices are developed.Equation 6.12 provides an approximate empiri-cal relationship between transformer kVA ratingand no-load losses, reflecting the fact that thepercentage of losses tends to decrease for largertransformers (Walling, 1992). This loss relation-ship is also used in the guidelines of Tables 6.6,6.7, and 6.8 provided later in this section.

Equation 6.10

where: kV = Rated phase-to-phase voltage of the transformer primary windingin kV; the voltage on the nameplate

Ct = Total capacitance in µF connected to the open phase, includingboth cable and internal transformer capacitance

Pnl = Three-phase, no-load loss of the transformer at rated excitationin watts

kV2CtPnl

≤ 0.00493

Equation 6.11

where: LGY = Length of cable in feet with connected transformer having thegrounded-wye primary winding and five-legged core

1CµF/M

26.0 – 2.48PnlkV2

kVA0.4

kV0.25LGY = Equation 6.12

Pnl = kVA [4.54 – 1.13 Log10 (kVA)]

EXAMPLE 6.1: Maximum Lengths of Cable Circuit Possible.

264 – Sect ion 6

For transformers that have small kVA ratingsand, consequently, low no-load loss wattage,highly efficient transformers, or transformerswith high primary voltage ratings, Equation 6.11can yield a negative maximum cable length. Ofcourse, a negative cable length is physicallymeaningless except that it indicates that thetransformer internal capacitance is likely to belarge enough that sustained voltages exceeding1.25 pu can occur for single-phase switching atthe transformer terminals.Example 6.1 illustrates the use of Equations

6.11 and 6.12.In comparison, with the delta-connected pri-

mary winding, all other parameters being thesame, the allowed length of cable found fromEquation 6.8 is 5.4 feet even if the transformer isassumed to have no capacitance. The maximumcable length calculated above (136 feet) is suffi-ciently long to permit single-pole switching inmany practical applications in which a singletransformer is fed radially from an overhead lineor from a switching compartment in a UD system.But, if the primary voltage level is 24.9 kV, andeverything else remains the same, Equations 6.12and 6.11 give a maximum allowable cable lengthof 24 feet. Lengths this short will not allow sin-gle-pole switching for any practical application.

6

LGY = 136 feet

kVA = 150 kVA = Nameplate kVA rating of the three-phasetransformer with the five-legged core

kV = 12.47 kV = Rated phase-to-phase voltage of the transformerprimary winding in kV

CµF/M = 0.312 µF/M = Capacitance of the shielded cable circuit inmicrofarads per mile

Placing these values into Equations 6.12 and 6.11 and solving the equationsgives the following.

From Equation 6.12:

Pnl = 150 [4.54 – 1.13 Log109 (150)] = 312.2 watts

From Equation 6.11:

10.312

26.0 – 2.48312.212.472

1500.4

12.470.25LGY =

Application Data Tables—MaximumCable LengthsWith Equation 6.11, and using Equation 6.12 toapproximate typical core losses, the length ofcable that can be switched with a five-leggedcore transformer with grounded-wye primarywinding is easily calculated. From this, applicationdata tables can be prepared from typical data.At the 12.47-kV primary voltage level, in many

cases the allowed cable lengths permit remotesingle-pole switching of radially fed transform-ers. But in 24.9-kV systems, the allowed cablelengths with the smaller and medium-size trans-formers are so short that, for most practical situa-tions, single-pole switching must be performedat the primary terminals of the transformers. For34.5-kV systems, as well as low-loss 24.9-kVtransformers, the internal transformer capaci-tances of the smaller kVA-rated transformers aresufficient to create ferroresonant overvoltages inexcess of 1.25 pu even when switched at the ter-minals without connected cable.

12.47-kV SystemsTable 6.7 lists the maximum cable lengths thatcan be energized or de-energized with the trans-former (unloaded) in a 12.47-kV system if thevoltages are not to exceed 1.25 pu during single-pole switching. Values are given for transformersfed by cables of three different sizes, and typicalcore loss values are assumed for each kVA rat-ing. For a transformer with greater no-load lossthan assumed here, the maximum cable lengthwill be longer. Likewise, a more efficient trans-former will have a shorter maximum length. Theeffect of loss variations do not make an exactlyproportional effect on maximum length becauseof the winding capacitance term (the secondterm on the right-hand side of Equation 6.11).Note the effect of cable size on allowed lengths.

24.9-kV SystemsTable 6.8 lists the maximum cable lengths thatcan be switched with the transformer in a 24.9-kV system if the voltages on the open phases arenot to exceed 1.25 pu. If the cable extends be-yond the transformer, but serves only one trans-former, the total length of cable being switchedshould be limited to the value given in the table.The maximum allowed cable lengths to limit


the voltage to 1.25 pu with the small and mediumkVA five-legged core grounded-wye transformersare very short. Single-pole switching of the cablecircuit and connected transformer cannot be per-formed in many practical systems. For the largerkVA transformers, the allowed cable lengths aresufficiently long that single-pole switching canbe performed.

34.5-kV SystemsTable 6.9 gives the maximum cable length with aconnected transformer that can be energized orde-energized with single-pole switches in a 34.5-kV system if the voltages on the open phases arenot to exceed 1.25 per unit. For the smaller kVAtransformers, overvoltages are likely with single-pole switching at the transformer terminals evenwithout connected cable. The allowed cablelengths are very short even with the larger kVAtransformers, virtually excluding the use of sin-gle-pole switches other than for switching at theprimary terminals of the larger transformerswithout cable connected to the de-energized ter-minals.

SWITCHING (OPERATING) PROCEDURES TOPREVENT FERRORESONANCEIf the cable lengths are longer than those listedin the tables or calculated from Equation 6.11,there are two options for preventing overvoltagesabove 1.25 pu. The first is to use only three-pole,gang-operated switches when energizing or de-energizing a cable circuit and connected trans-former. The second is to do single-pole switchingat the primary terminals of the transformer sothat, when the transformer is being energized orde-energized, no cable is connected to the de-energized primary terminals. Although this ap-proach is effective for any size transformer at15-kV and below, it may not limit the overvolt-ages to 1.25 pu with the smaller kVA, low-loss24.9- and 34.5-kV transformers. To limit the volt-ages in these cases, install a three-pole switchingdevice in the transformer.

Single-Pole SwitchesFor situations in which overvoltages above 1.25pu will not occur from single-pole switching atthe primary terminals of the five-legged core

6Maximum Cable Length in Feetfor the Indicated Cable Size

Transformer Assumed No-Load Grounded-Wye PrimaryNameplate (kVA) Loss (w) #2 1/0 4/0

75 182 100 87 64

112.5 250 144 126 93

150 312 184 161 119

225 423 257 225 166

300 522 323 283 208

500 745 473 413 305

750 968 623 545 401

1,000 1,150 745 652 480

1,500 1,426 930 813 599

2,000 1,619 1,057 924 681

2,500 1,750 1,141 998 735

Note. Cable capacitances of #2, 1/0, and 4/0 cables are 0.230, 0.263, and 0.357 µFarads/mile, based on 220 mils of TR-XLPE insulation. Allowed cable lengths are longer with260-mil insulation because of lower capacitance.

TABLE 6.7: Maximum Allowed Cable Lengths in 12.47-kV Systems toLimit Open-Phase Voltages to 1.25 PU.

Maximum Cable Length in Feetfor the Indicated Cable Size

Transformer Assumed No-Load Grounded-Wye PrimaryNameplate (kVA) Loss (w) 1/0 4/0

75 182 5 4

112.5 250 12 10

150 312 19 15

225 423 31 25

300 522 42 34

500 745 69 56

750 968 96 77

1,000 1,150 118 95

1,500 1,426 151 122

2,000 1,619 172 139

2,500 1,750 185 149

Note. Cable capacitances of 1/0 and 4/0 cables are 0.256 and 0.318 µFarads/mile, based on260 mils of TR-XLPE insulation.


266 – Sect ion 6

grounded-wye transformers (power factor ca-pacitors are not connected to the secondary),switching procedures exist that allow the ener-gization of the smaller kVA transformers con-nected to, or at the end of, long cable circuits.Such procedures will be illustrated with thearrangement in Figure 6.11, where the cable cir-cuit does not extend beyond the transformer.

6Maximum Cable Length in Feetfor the Indicated Cable Size

Transformer Assumed No-Load Grounded-Wye PrimaryNameplate (kVA) Loss (w) 1/0 4/0

75 182Do not switch single-phase,112.5 250

even at terminals150 312

225 423 1 1

300 522 5 4

500 745 16 13

750 968 26 21

1,000 1,150 35 28

1,500 1,426 47 38

2,000 1,619 71 54

2,500 1,750 58 47

Note. Cable capacitances of 1/0 and 4/0 cables are 0.256 and 0.318 µFarads/mile, based on260 mils of TR-XLPE insulation.


To energize the cable and transformer, openthe single-pole switching devices at the trans-former; of course, the switching devices for thecable circuit are open. Then close the single-pole switches for the cable circuit to energizejust the cable. Finally, close the single-poleswitches at the transformer to energize theunloaded transformer.To de-energize the transformer and cable cir-

cuit in Figure 6.11, use the opposite procedure.Specifically, open the single-pole device at thetransformer. Then open the single-pole switchesto de-energize the cable.Although the preceding example is for the

simple case of a radially fed transformer at theend of the cable circuit, it can be adapted to ra-dial systems with more than one transformer andto multiple cable segments. This is discussedlater in this section.

Three-Pole SwitchesThree-pole switches allow the energization andde-energization of the circuit and unloaded trans-former with grounded-wye primary without fer-roresonant overvoltages if the switch pole spandoes not exceed one cycle. Furthermore, thethree-pole switch will prevent ferroresonant over-voltages even if power factor capacitors are con-nected to the secondary side of the transformer.Three-pole switches in the lower kVA, low-

loss 24.9- and 34.5-kV transformers also will pre-vent overvoltages above 1.25 pu that otherwisecan occur with single-pole switching at the pri-mary terminals.

Ferroresonancewith Cable-Fed,Three-PhaseTransformers withGrounded-WyePrimary Windingsand TriplexConstruction

With grounded-wye primary windings and five-legged core construction, there are limitationson allowed cable lengths, especially at the 24.9-and 34.5-kV primary voltage levels, when ener-gizing and de-energizing cable circuits and con-nected transformers with single-pole switches.Switching procedures exist that allow single-poleswitching without producing overvoltages above1.25 pu with the five-legged core grounded-wyetransformer, excluding the lower loss, lower kVA24.9- and 34.5-kV transformers. But these proce-dures may be difficult to implement with multi-ple transformers on a circuit.

FIVE-LEGGED CORE, GROUNDED-WYETRANSFORMER TANK HEATINGThe five-legged core transformer with grounded-wye primary windings can experience severetank heating during certain unbalances in thesystem. Although the five-legged core preventstank heating for most unbalances, some unbal-ances have caused transformer fires. Figure 6.13illustrates how this happens.With a solid ground fault on phase A of the

shielded cable circuit, the riser-pole fuse in thefaulted phase blows. The voltage from terminalH1 to ground at the transformer is zero, with


The five-legged core prevents tank heating intransformers with the grounded-wye primarywindings during phase-to-ground faults whetheror not single-pole overcurrent devices are in-stalled in the primary feeder. All faults on circuitsmade with concentric neutral cable will be fromone or more phases to ground. Consequently,when all segments of the primary feeder be-tween the substation and transformer are madewith concentric neutral cable, tank heating infive-legged core transformers is unlikely.Line-to-ground faults, with only the overcur-

rent devices in the faulted phases opening,would have caused excessive tank heating if thetransformer in the preceding example had beenconstructed on a three-legged core.If a solid ungrounded phase-to-phase fault

occurs from phases B to C in Figure 6.13 on theoverhead line and the fuse in only one of thetwo faulted phases blows, say phase B, thenphase C voltage is applied to terminals H2 andH3 of the transformer and phase A voltage is ap-plied to terminal H1. That is, the same voltage isapplied to two of the primary phases downstreamfrom the fuses and to two of the high voltageterminals of the transformer. A solid ungrounded

fault can occur in an overheadline if an insulator breaks at anangle pole and the phase con-ductor is pulled across one ofthe other two phase conduc-tors. Manufacturing tolerancesand/or different preloadingsare reasons only one of thetwo line fuses blows.An ungrounded phase-to-

phase fault also happens whenline crews jumper two phasestogether to bring temporaryservice to single-phase con-sumers following a fault. These

conditions impress approximately 58 percentzero-sequence voltage across the primary wind-ings of the transformer, induce currents into thetank, and cause tank heating unless the trans-former is quickly de-energized. Because the five-legged core transformer is not symmetrical, thetime to produce high temperatures is a functionof which two terminals are fed from the same

6

FIGURE 6.13: Overhead System Supplying a Cable-Fed, Grounded-WyeTransformer on a Five-Legged Core.

Shielded Cable Circuit

Pad-Mounted TransformerFive-Legged Core

Cable Capacitance

MultigroundedNeutral

Overhead

MGN

Feeder

Cable Shield andConcentric Neutral

NoLoad

X1

X2X3

XC

XC

XC

H3

φA

φA φB φC

φC

φB

H2

H1

Line Fuses

Single-Phase Reclosers

Riser Pole

Surge Arresters

Fused Cutouts

approximately rated voltageapplied from terminal H2 toground and from terminal H3to ground. The current in theB and C phase fuses at theriser pole is due to the loadon the transformer and a smallcomponent fed back to theground fault on phase A. Con-sequently, the fuses in phasesB and C do not blow and thetransformer remains energizeduntil switching is manuallyperformed. Because the trans-former is constructed on a five-legged core, tankheating does not occur. Similarly, if the solidfault to ground (concentric neutral) involves twoof the single-conductor cables in Figure 6.13, thefuses at the riser pole supplying the two faultedphases blow and one phase of the transformerremains energized until switching is manuallyperformed, but tank heating does not occur.

Five-legged core

transformers with

grounded-wye

primary windings can

experience severe tank

heating during certain

system unbalances.

268 – Sect ion 6

primary phase, the induction level at rated volt-age, and other design parameters. Regardless,tanks have heated the oil above the flash point,which caused the bushings to leak oil, whichcaused a fire.Ungrounded three-phase solid faults on over-

head feeders, with only two of the three single-pole overcurrent devices opening, energize allthree phases downstream from the overcurrentdevices at the same voltage. Then the same volt-age is applied to all three HV terminals of thefive-legged core transformer. Because the un-grounded three-phase fault applies 100 percentzero-sequence voltage, the tank currents arehigher and heating occurs in a shorter time thanfor the ungrounded phase-to-phase fault. Duringthese conditions, the currents in the transformerfuses usually are not high enough to blow thefuse unless a short circuit develops.The I2R losses in the tank from the tank cur-

rents are the main source of heating. The tankheating raises the transformer oil temperaturebecause there is an inward heat flow. A fewusers have applied eutectic fuse links inside thefive-legged core transformer to sense oil temper-ature and de-energize the transformer before theoil reaches the flash point, the bushings leak, ora fire starts. The effectiveness of the eutecticfuse links is not documented in the literature.However, several utilities have indicated the eu-tectic fuse links prevented severe tank heatingthat otherwise would have occurred with fuselinks that do not respond to oil temperature.If only three-pole overcurrent devices are in

the primary circuits (see Figure 6.13), tank heat-ing with a five-legged core transformer will notoccur from ungrounded phase-to-phase faults because allthree phases are de-energized.Or, if ungrounded phase-to-phase faults are impossible be-cause concentric neutral cableis used for all primary circuitsfrom the station to all trans-formers, tank heating will notoccur, even when single-poleovercurrent devices are used.However, if a primary phase

opens in the absence of a fault, the five-leggedcore transformer may experience tank heating,

depending on the connection of the secondaryload. In Figure 6.13, assume a fuse opens at theriser pole and sufficient load is connected to thesecondary such that the secondary load deter-mines the voltage appearing at the transformerterminals. That is, the primary cable is so shortthat its capacitance is not a factor. If all sec-ondary load is constant impedance connectedfrom phase to neutral, tank heating will notoccur. The voltage on the open phase will col-lapse to zero, just as for a ground fault on theprimary cable. If all secondary load is constantimpedance connected from phase to phase, andbalanced, the voltages impressed on the trans-former have a zero-sequence component of 50percent and tank heating can occur. If all load isthree-phase induction motors that maintain aspeed such that the motors’ negative-sequenceimpedance is less than one-half the motors’ pos-itive-sequence impedance, tank heating will notoccur. In an actual system, the total secondaryload is connected from both phase to phase andphase to neutral and may not be balanced, anda portion is induction motor; thus, it is difficultto predict whether tank heating will occur withjust an open phase. Regardless, tank heating in-cidents have occurred for an open primaryphase in the absence of a fault.

TRIPLEX TRANSFORMER CORECONFIGURATION…Three-phase distribution transformers withtriplex construction have three single-phasecore-coil assemblies inside a common tank, asillustrated in Figure 6.14. When the primarywindings are connected in grounded-wye and

the secondary windings areconnected in either grounded-wye or ungrounded-wye,there is no magnetic couplingbetween phases of the trans-former. There is no possibilityof tank heating for unbalanceswhere two or three terminalsof the transformer are ener-gized at, or below, rated volt-age from the same primaryphase. Also, they are not sus-

ceptible to ferroresonance during single-poleswitching, regardless of the primary circuit

6

Triplex transformers

with grounded-wye

primary windings are

not susceptible to

ferroresonance.


length or voltage, if it is made with single-con-ductor shielded cables and ungrounded capaci-tors are not connected to the secondary systemat the time of switching.

…WITHOUT SECONDARY POWER FACTORCORRECTION CAPACITORSFigure 6.15 shows a triplex transformer withgrounded-wye primary and grounded-wye sec-ondary windings fed through single conductorshielded cables. With no capacitive coupling be-tween phases of the primary cable circuit, withno magnetic coupling between phases of thetransformer, and with no load on the secondary,single-pole switching does not cause ferroreso-nance or overvoltages, regardless of the lengthof the primary cable circuit.If lagging power factor load is connected to

6

FIGURE 6.14: Triplex-Type Wound Core with Grounded-Wye PrimaryWindings.

H1 H2 H3

FIGURE 6.15: Cable-Fed, Triplex-Core Transformer with Grounded-Wye Primary Windings.

Shielded Cable Circuit Pad-Mounted TransformerTriplex Core

Cable Capacitance

X1

X2X3H3

φC

φBH2

L

H1

Surge Arresters

Fused Cutouts

NoLoad

the secondary during single-pole switching, volt-age appears on the open primary phases. Thevoltage is due to the phase-to-phase connectedload on the secondary applying voltage to thesecondary (LV) terminals corresponding to theopen primary phases. The magnitude of thevoltage to ground on the open primary phase isdetermined primarily by the ratio of the phase-to-ground load to the phase-to-phase load onthe secondary side, the magnitude and powerfactor of the phase-to-phase secondary load,the transformer leakage impedance, and thephase-to-ground capacitive reactance of theprimary feeder. The phase-to-ground voltageon the open phase almost always is less thannominal, although voltages five to 10 percentabove nominal phase-to-ground voltage aretheoretically possible.

…WITH SECONDARY POWER FACTORCORRECTION CAPACITORSIf capacitors are connected to the secondaryside of the triplex-core transformer having thegrounded-wye primary windings and grounded-wye secondary windings, single-pole switchingremote from the transformer or at the trans-former, with no other load connected to thesecondary, may cause ferroresonance. Whetherit does depends on the connections of the sec-ondary capacitors.If the capacitors are connected in grounded-

wye (from phase to neutral) on the secondary

φA

TransformerSwitch

270 – Sect ion 6

system ahead of the service disconnect switch inFigure 6.15, ferroresonance and overvoltageswill not occur for single-pole switching on theprimary side, either at the primary terminals ofthe triplex-core transformer or remote from thetransformer.If the capacitors are connected in delta or un-

grounded-wye on the secondary system aheadof the service disconnect switch in Figure 6.15,ferroresonance and overvoltages can occur forsingle-pole switching on the primary side, eitherat the primary terminals of the triplex-core trans-former or remote from the transformer. Most ca-pacitors for application in low-voltage secondarysystems are connected in delta. Thus, when sin-gle-pole switching is performed on the primary

side of the triplex-core transformer, secondarycapacitors should be disconnected.In UD systems with single-pole switching on

the primary, three-phase transformers supplyingfour-wire wye services, as well as three-wiredelta services, should have grounded-wye pri-mary windings. The secondary is connected ingrounded-wye or ungrounded-wye. With triplexconstruction, the possibility of tank heating andferroresonance, which can occur with five-legged core transformers, is virtually eliminated.Also, there is no need to develop special switch-ing procedures to prevent ferroresonance.Triplex transformers are, however, inherentlyheavier and may cost more than five-legged,wound-core designs.

6

Ferroresonancein UndergroundFeeders HavingMore Than OneTransformer

When there is more than one three-phase trans-former on a cable circuit when single-poleswitching is performed, the total length of cablebeing switched should be limited so that thevoltage to ground does not exceed 1.25 pu.DiPietro and Hopkinson (1976) studied this

situation. Their investigations were performedon the TNA with transformers having the delta-connected HV windings. They concluded thatthe criterion for limiting the voltage to groundon the open phase to 1.25 pu was the same as ifthere were just one transformer on the circuit,provided an equivalent capacitive reactance and

an equivalent magnetizing reactance were found.This method can be extended to five-leggedcore, grounded-wye primary transformers, usingthe no-load-loss-based approach presented inthis section.

APPLICATION CRITERIATransformers with delta or ungrounded-wye pri-mary windings are not recommended in UD sys-tems that use single-pole switching. If triplex-coretransformers are used, ferroresonance is not aconcern and operators can design and switch thesystem without developing complex procedures.

FIGURE 6.16: Circuit with “S” Cable Sections and “N” Five-Legged Core Grounded-Wye PrimaryTransformers.

Fused Single-Pole Switches

Symbols

Lj - Length of section j in feetCj - Capacitance of section j in µf/mile

L1(C1)

SW1

L2(C2) Lj(Cj)

T1kVA1PNL1

TikVAiPNLi

T2kVA2PNL2

TNkVANPNLN

L3(C3)

LS(CS)

TN-1kVAN-1PNLN-1


The multiple transformer criterion given is forcable circuits with transformers having thegrounded-wye primary windings and constructedon a five-legged core. With reference to the sys-tem in Figure 6.16, which has “S” three-phasecable sections and “N” three-phase transformers,the voltage to ground during single-pole switch-ing at SW1 will not exceed 1.25 pu if the in-equality of Equation 6.13 is satisfied.When Equation 6.13 is applied, the number of

three-phase cable sections, “S,” and the number ofthree-phase transformers, “N,” on the circuit neednot be the same. Each cable section “j” can havea different length and capacitance pu of length,and each transformer “i” can have different no-load loss and kVA rating. There are no restrictionsin the topology of the circuit to which Equation6.13 applies. However, it assumes all transform-ers are three-phase, five-legged core units.Application of Equation 6.13 is demonstrated

with the three-phase system in Figure 6.17 andExample 6.2, assuming the system phase-to-phase voltage is 12.47 kV. Table 6.10 lists thetransformer and cable data for the system.

6

FIGURE 6.17: Circuit Configuration for Switching Example 6.2.

Fused Single-Pole Switches

3-Way Junction

Symbols

- Normally closed separable connector- Normally opened separable connector

Lj - Length of section j in feetCj - Capacitance of section j in µf/mile

L1(C1) L2(C2) L3(C3)

T1kVA1PNL1

T2kVA2PNL2

T4kVA4PNL4

T3kVA3PNL3

L5(C5)

L4(C4)

N.O.N.C.

Equation 6.13

where: CjµF/M = Capacitance of cable section “j” in microfarads per mileLj = Length of cable section “j” in feetS = Number of cable sections in the system during the switching

operationkVAi = Nameplate kVA rating of three-phase transformer “i” that is

connected to the circuit being switchedPnli = No-load loss in watts of three-phase transformer “i” that is

connected to the circuit being switchedkV = Rated phase-to-phase voltage in kV of the primary windings of

the transformers on the circuit; all transformers are assumed tohave the same rated voltage

N = Number of transformers connected to the cable circuit duringthe switching

[C1µF/ML1 + C2µF/ML2 + CjµF/MLj + CSµF/MLS] +

2.476kV0.25

[kVA10.4 + kVA2

0.4 + kVA0.4 + kVAN0.4 ] ≤

26kV2

[Pnl1 + Pnl2 + Pnli + PnlN]

272 – Sect ion 6

If all transformers in Figure 6.17employed triplex construction(grounded-wye primary windings),the entire system could be ener-gized by closing the single-poleswitches at the source end of cablesection 1, and voltages above 1.25pu would not occur. Triplex trans-formers greatly simplify operatingprocedures, reduce the time to en-ergize or de-energize a circuit withmultiple transformers, and preventferroresonance if a conductor orjumper opens at light load.

SWITCHING (OPERATING)PROCEDURES TO PREVENTVOLTAGES ABOVE 1.25 PUWhen transformers have grounded-wye primary windings (five-leggedcore), procedures can be developedthat allow single-pole switching ofthe cable circuit and connectedtransformers without producingvoltages above 1.25 pu. This ispossible because switching at theprimary terminals without cableconnected to the de-energized pri-mary terminals and without capaci-tors on the secondary does notproduce voltages above 1.25 pu(excluding the lower loss, lowerkVA units in 724.9- and 34.5-kVsystems).

6Transformer Data Cable Circuit Data

Rating No-Load Section CapacitanceNumber (kVA) Loss (w) Number Size (AWG) Length (feet) (µF/mile)

T1 500 745 1 4/0 330 0.427

T2 225 850 2 4/0 280 0.427

T3 300 810 3 4/0 350 0.427

T4 75 182 4 4/0 1,500 0.427

5 2 130 0.269

Note. Based on 175 mil TR-XLPE Insulation.

TABLE 6.10. Transformer and Cable Data for the System of Figure 6.17.

EXAMPLE 6.2: Energizing Multiple-Transformer System with Single-Pole Switches.

In Figure 6.17, transformers T1, T2, and T3 are loop-feed units with two HV bushings per phase, andtransformer T4 is a radial-fed unit supplied from the three-way junction. The normally open point ofthe loop is at transformer T3. To determine if the entire system can be energized with the single-pole switches at the source end of cable section 1, assuming that load is not connected to thetransformers, place the data in Table 6.10 into Equation 6.13 as follows:

As 1,133 is not less than 432, single-pole switching at the source end of cable section 1 causesphase-to-ground voltages above 1.25 pu. The data in Table 6.10 show that cable section 4 is quitelong, 1,500 feet, which suggests that disconnecting cable section 4 from transformer T2 may en-able energizing transformers T1, T2, and T4 with single-pole switching at the source end of cablesection 1. Assuming that cable section 4 is disconnected from transformer T2, placing the datainto Equation 6.13 gives the following:

As 480 is still more than 297, this example illustrates that energizing practical multitransformerloop circuits on a single-pole switching basis often cannot be performed without creating ferrores-onant overvoltages in excess of 1.25 pu, even on 12.47-kV circuits.

[(330 × 0.427) + (280 × 0.427) + (350 × 0.427) + (1,500 × 0.427) + (130 × 0.269)] +

2.47612.470.25

(5000.4 + 2250.4 + 3000.4 + 750.4) ≤ 0.167(745 + 850 + 810 + 182) or

1,133 > 432

[(330 × 0.427) + (280 × 0.427) + (350 × 0.427) + (130 × 0.269)] +

2.47612.470.25

(5000.4+ 2250.4 + 750.4) ≤ 0.167(745 + 850 + 182) or

480 > 297


Also, if only three-pole switching is per-formed to energize the cable circuit and con-nected transformer, overvoltages will not occur.

Single-Pole SwitchesFigure 6.17 shows numerous possibilities for en-ergizing or de-energizing a system with single-pole switches when the transformers are loopfeed and load-break separable connectors areused at each transformer, junction, and switch-ing compartment. With Equation 6.13, switchingprocedures can be developed for taking a circuitout of service and then restoring it, so that thevoltages do not exceed 1.25 pu. For radially fed

transformers, tables can be developed giving themaximum length of cable that can be switchedwith a transformer of a given size. Ferroreso-nance always should be considered when youare switching in UD systems.

Three-Pole SwitchesThree-pole switches at switching enclosures andin three-phase loop-feed transformers with thegrounded-wye primary windings will allow thegreatest flexibility for energizing and de-energiz-ing circuits and connected transformers. Howev-er, having three-pole switches at each loop-feedtransformer may be difficult to justify economically.

6

Summary ofTechniques forPreventingFerroresonance inUndergroundSystems

There are two options for preventing ferroreso-nance under all conditions that can exist in theUD system if all capacitor banks are connected ingrounded wye. First, use only three-pole switch-es to energize and de-energize cable circuits andtheir connected transformers if any of the trans-formers have primary windings connected in ei-ther delta, floating-wye, or grounded-wye wind-ings. The second option, which enables single-pole switching of the cable circuit and connect-ed transformer, uses only grounded-wye primarywindings and triplex construction for three-phasetransformers, or else uses three single-phasetransformers with grounded-wye primary connec-tion. This second option also prevents ferroreso-nance should a jumper or conductor open underlight load conditions. The second option is therecommended approach for new systems and ad-ditions. Also, cable-fed transformers with open-wye/open-delta connections are not susceptibleto ferroresonance during single-pole switching.For conditions other than those defined above,

the possibility of ferroresonance always exists.However, design and operating procedures thatlimit the voltages on the open phases to 1.25 puduring single-pole switching are available. Theseare summarized in the following subsections.

DISTRIBUTION SYSTEM DESIGNPrimary Cable Circuit LengthFerroresonant overvoltages can be limited to1.25 pu, when designing the system, by limitingthe length of the primary cable circuit that can

be switched with the transformer. When thetransformers have ungrounded primary wind-ings, limiting the length is almost always notpractical. Furthermore, single-pole switching atthe primary terminals of the transformer withungrounded primary windings can produce volt-ages to ground above 1.25 pu.When the transformers have grounded-wye

primary windings and are constructed on a five-legged core, the cable lengths that can be ener-gized or de-energized with single-pole switcheswithout producing voltages above 1.25 pu arelong enough that systems can be designed andoperated at the 12.47-kV primary level for manysituations. But at the 24.9-kV voltage level, andespecially at the 34.5-kV voltage level, the cablelengths are short. With the lower loss, lowerkVA transformers used in 24.9- and 34.5-kV sys-tems, overvoltages above 1.25 pu occur whenswitching at the terminals of the transformer.

Three-Pole SwitchesAnother system design option for controlling over-voltages is to use only three-pole switches at loca-tions where single-pole switching of the cablecircuit and connected transformer(s) will pro-duce voltages above 1.25 pu. If the transformershave ungrounded primary windings, a largenumber of three-pole switches will be required.When the five-legged core transformers have

grounded-wye primary windings, the number ofthree-pole switches required in the 15-kV classsystems may be small because of the relatively

274 – Sect ion 6

long lengths of cable and connected transformersthat can be switched with single-pole switches.But at the 24.9- and 34.5-kV voltage levels, thelengths of cable that can be switched with five-legged core, grounded-wye primary transformersare much shorter, by factors of approximatelyfour and nine, respectively.

DISTRIBUTION SYSTEM OPERATION(SWITCHING PROCEDURES)With existing distribution systems, switchingprocedures can be developed that limit overvolt-ages during single-pole switching operations to1.25 pu when the transformers have grounded-wye primary windings and a five-legged core.Implementation of these switching proceduresrequires that switching devices—such as load-break elbow connectors, fused or solid discon-nects, or internal under-oil switches—are locat-ed at the transformer primary terminals. Theycan be used in 15-kV and lower voltage systemshaving five legged-core transformers with ground-ed-wye primary windings because switching atthe primary terminals, without connected cable,does not result in objectionable overvoltages.They can also be used in 24.9- and 34.5-kV sys-tems if it is recognized that 1.5 pu overvoltagesmay occur when switching the lower loss, lowerkVA grounded-wye transformers at their termi-nals. However, implementing these proceduresin the field may be difficult, especially whenrestoring service during and after severe storms.These switching procedures generally are not

practicable in systems with delta or ungrounded-wye primary windings because overvoltages

above 1.25 pu may occur for single-pole switch-ing at the primary terminals of the transformer.To recap the switching procedures for limiting

overvoltages during single-pole switching, consid-er a system represented by Figure 6.18. Assumingthat energizing cable section 1 (SEC 1) and thetransformer with single-pole switches at locationSW1 produces voltages above 1.25 pu, either of thefollowing two switching procedures could be used.First, assume the single-pole switches at loca-

tions SW1, SW2, and SW3 are open but theswitches are closed at location SW4. This repre-sents the situation in which the transformer isloop feed with load-break elbow connectors, orinternal loop-feed switches, but does not have afield-operable disconnect between the loop-feedbus of the transformer and the primary winding.To energize the system, do the following:

1. Close the switches at location SW1 to ener-gize cable section 1 (SEC 1).

2. Close the switches at location SW2 to ener-gize the transformer.

3. Close the switches at location SW3 to ener-gize cable section 2 (SEC 2) up to the nor-mally open point.

If the switches at SW3 were closed before thesingle-pole switches at SW2 were closed, cablewould be connected to the de-energized pri-mary terminals of the transformer, and overvolt-ages could occur for single-pole switching atlocation SW2.Second, assume the single-pole switches are

open at all four locations shown in Figure 6.18.

6

FIGURE 6.18: Single-Line Diagram of a Portion of a UD System.

Single-Pole Switching Devices

Single-Pole Switches orFused Disconnect Devices

Five-Legged Core

SEC 1 SEC 2SW2

SW4

SW3SW1

N.O.


This represents the situation in which the trans-former is loop feed with internal single-poleswitching devices for connecting the transformerprimary windings to the internal loop-feed bus.To energize the transformer and cables, closethe single-pole switches at locations SW1 andSW2. The order of closing is not significant froma ferroresonance standpoint because the switchesat location SW4 are open. Then the transformerwindings are energized by closing the single-pole switching devices at location SW4, eitherbefore or after the switches at location SW3 areclosed to energize cable section 2 (SEC 2).In developing switching procedures to pre-

vent or limit ferroresonant overvoltages, the co-operative should consider whether it matters ifliquid-filled transformers are energized withswitching devices at their primary terminals or ata remote location.

SELECTION OF DISTRIBUTIONTRANSFORMER CONNECTIONSTransformer connections in UD systems affectthe likelihood of ferroresonance during single-pole switching of cable circuits and connectedtransformers (or just one transformer). In gen-eral, delta and ungrounded-wye connected pri-mary windings should not be used for cable-fedtransformers in 15-, 25-, and 35-kV class UD sys-tems, unless only three-pole switches are used.For transformers in UD sys-

tems, grounded-wye primarywindings are preferred. Withtriplex-core three-phase trans-formers and banks of single-phase transformers withgrounded-wye primary wind-ings, ferroresonance will notoccur during single-poleswitching of cables and con-nected transformers. With thefive-legged core, voltagesabove 1.25 pu will occur ifcable lengths are too long, orif switching is done at the pri-mary terminals of the lower loss, lower kVA24.9- and 34.5-kV transformers. When the cablelengths are greater than the length allowed tolimit voltages to 1.25 pu, switching procedures

that prevent overvoltages above 1.25 pu usuallycan be developed. Implementation of these proce-dures may be difficult under practical conditions.For the basic types of services supplied by

three-phase transformers, or banks of single-phase transformers, the preferred winding con-nections in the UD system, from a ferroreso-nance standpoint, are defined below.

Four-Wire Wye ServicesFigure 6.1 shows the two most common con-nections for supply of four-wire wye services.Delta/grounded-wye connections should beavoided in cable-fed transformers unless onlythree-pole switching devices are used.Grounded-wye/grounded-wye connections

should be used in transformers supplying four-wire wye services in UD systems. Triplex con-struction of three-phase transformers, or use ofthree single-phase transformers, prevents fer-roresonance and eliminates the possibility oftank heating that can occur with the five-leggedcore transformer. Triplex construction is recom-mended for three-phase units. Use of five-leggedcore, three-phase transformers with grounded-wye primary windings usually prevents voltagesabove 1.25 pu for switching at the primary ter-minals and with reasonable lengths of cableconnected to the primary terminals.

Four-Wire and Three-WireDelta ServicesFigure 6.1 shows transformerwinding connections for sup-plying the 240/120-volt, four-wire and 240-volt, three-wiredelta services. Delta/delta,floating-wye/delta, and open-delta/open-delta connectionsshould be avoided if single-pole switching of cable circuitand connected transformers iscontemplated. These connec-tions are acceptable only ifthree-pole switches are used

for all switching operations.Open-wye/open-delta connections prevent

ferroresonant overvoltages during single-poleswitching of cable circuits and connected

6

Transformer

connections in UD

systems affect the

likelihood of

ferroresonance

during single-pole

switching.

276 – Sect ion 6

transformer. However, these connections are notsymmetrical and are a source of voltage unbal-ance. Intentional oversizing ofthe transformers in this config-uration will minimize voltageunbalance on the secondaryside. As long as the connec-tions do not cause objection-able voltage unbalance, andthe possibility of energizingboth high-voltage terminalsfrom the same primary phaseis minimal, these are the rec-ommended connection forcable-fed transformers. Other-wise, delta/delta or floating-wye/delta connec-tions must be used with appropriate installationof three-pole, gang-operated switches and oper-ating procedures to prevent ferroresonance.

Another option is to provide two separateservice voltages. The 240-volt, three-wire load is

supplied from a triplex-coregrounded-wye/grounded-wyetransformer with a secondaryrated 240Y/138 volts. The neu-tral point of the wye-connect-ed secondary windings maybe grounded or floating. The120/240-volt, single-phaseload is supplied from a single-phase transformer with itsprimary connected from phaseto neutral. The experience ofthe cooperative with the open-

wye/open-delta connection in overhead systemscan serve as a benchmark in determining theacceptability of the connections for cable-fedtransformers.

6

Use grounded-wye

primary windings

and triplex cores

in three-phase

transformers to avoid

ferroresonance.


Ferroresonance in UD systems is a complexphenomenon. The probability of its occurringand the severity of the associated overvoltagesare a function of many parameters. If the follow-ing recommendations are observed in the designand operation of the system and in the selectionof transformer connections, problems caused byferroresonance will be minimized. If only ground-ed-wye primary windings and triplex cores areused in three-phase transformers, ferroresonanceduring single phasing is virtually impossible. It isnot necessary to develop special switching oroperating procedures, use three-pole switches,or limit cable length as may be required withfive-legged core transformers with grounded-wye primary windings. Triplex construction ofthree-phase transformers with grounded-wyeprimary windings prevents tank heating.

1. For service to four-wire wye loads from12.47-, 24.9-, and 34.5-kV UD systems, usegrounded-wye/grounded-wye winding con-nections. If the three-phase, cable-fed trans-former is constructed on a five-legged core,there are limits on the length of cable with aconnected transformer that can be energizedor de-energized with single-pole switches so

that the overvoltages are limited to 1.25 pu.Do not exceed these cable lengths. If thephysical location of the equipment makes itimpossible to limit the length of cable, de-velop switching procedures whereby thecable circuit can be energized or de-ener-gized with the transformer(s) disconnectedfrom the cable circuit. Switching at the pri-mary terminals of the lower loss, lower kVAgrounded-wye primary five-legged coretransformers in 24.9- and 34.5-kV systemsmay produce voltages above 1.25 pu. If thethree-phase transformer has triplex construc-tion, there are no limits on cable length dur-ing the single-pole switching of the cablecircuit and transformer with grounded-wyeprimary windings. Triplex core transformerswill not experience tank heating as is possi-ble with five-legged core transformers withgrounded-wye primary windings.When purchasing three-phase transform-

ers with grounded-wye/grounded-wye wind-ing connections, always consider bothtriplex and five-legged core designs, espe-cially in the lower kVA sizes. Always pur-chase triplex designs if their evaluated cost(includes first cost, cost of losses, etc.) is less


than or equal to that of the five-legged coreunit. Because the triplex designs simplifyswitching and operating procedures andeliminate the possibility of tank heating, thesebenefits should be evaluated in the purchas-ing decision. Installation of three single-phasetransformers, from a ferroresonance and tank-heating standpoint, offers the same advan-tages as do the triplex design transformers.

2. For service to three-wire ungrounded (delta)loads from the 12.47-, 24.9-, and 34.5-kV UDsystems, use the grounded-wye/floating-wyewinding connection. This connection mayalso be used to supply the corner-groundeddelta secondary system by grounding one ofthe secondary phase conductors. If the three-phase, cable-fed transformer is constructedon a five-legged core, there are limits on thelength of cable with a connected transformerthat can be energized or de-energized withsingle-pole switches so that the overvoltagesare limited to 1.25 pu. Do not exceed thesecable lengths. If the physical location of theequipment makes it impossible to limit thelength of cable, develop switching procedureswhereby the cable circuit can be energizedor de-energized with the transformer(s) dis-connected from the cable circuit. If the three-phase cable-fed transformer has triplexconstruction, there are no limits on cablelength during the single-pole switching ofthe cable circuit and connected transformerwith grounded-wye primary winding.When purchasing three-phase transformers

with grounded-wye/floating-wye windingconnections, always consider both triplex andfive-legged core designs, especially in thelower kVA sizes. Always purchase triplex de-signs if their evaluated cost (including firstcost, cost of losses, etc.) is less than or equalto that of the five-legged core unit.Three-phase transformers for this appli-

cation either should have the neutral of theprimary windings connected to the trans-former tank or else should have the primaryneutral brought out through a separate insu-lated bushing. When the neutral of the high-voltage winding is brought out throughan insulated bushing, the neutral should

always be grounded before the transformeris energized.The neutral point of the low-voltage

windings rated 480Y/277 volts, in eithercase, should be brought out through an in-sulated bushing so that the transformer canserve either a four-wire grounded wye sec-ondary, a three-wire delta (ungrounded) sec-ondary system, or a corner-groundedsecondary system. When the transformerserves the ungrounded or corner-groundedsystems, the secondary neutral bushing (ter-minal) should be insulated by the coopera-tive to avoid unintentional grounding. Whenthe low-voltage windings are rated 240Y/138volts to supply a 240-volt ungrounded orcorner-grounded system, the neutral may ormay not be brought out, depending on thepreference of the user. However, if the sec-ondary neutral is not brought out on an in-sulated bushing, it must be floated (isolated)within the tank.

3. For service to 240/120-volt four-wire deltaloads in the 12.47-kV UD system employingsingle-pole switching of cable circuit andconnected transformers, use open-wye/open-delta connections. An alternative is to pro-vide two separate services. The 240-volt,three-wire service is supplied from a triplex-core transformer or three single-phase trans-formers with the primary and secondarywindings connected in grounded wye. Thesecondary winding of the three-phase unitmust be rated 240Y/138 volts. The single-phase 120/240-volt service is supplied froma single-phase transformer with its primarywinding connected from phase to neutral.Some utilities discourage new applications

for the 240/120-volt, four-wire delta services.Instead, they promote four-wire wye serviceat 208Y/120 volts. This type of service al-lows use of grounded-wye/grounded-wyeconnections with triplex construction.If only three-pole switching is used to en-

ergize or de-energize the cable circuit andconnected transformers, delta, open-delta, orfloating-wye connections may be used forthe primary windings, provided three-poleswitches are also installed at each transformer

6

278 – Sect ion 6

to connect and disconnect the transformerfrom the cable. The advantage of the closed-delta connection is that the maximum possi-ble voltage unbalance, under worst-caseconditions, is lower than with the open-wye/open-delta connections.

4. For service to 240/120-volt, four-wire deltaloads in 24.9- and 34.5-kV systems, useopen-wye/open-delta connections. An alter-native is to provide two separate services asdescribed in recommendation three, or elsepromote the 208Y/120-volt, four-wire wyeservice over the four-wire delta service withgrounded-wye windings.If only three-pole switching is used to en-

ergize and de-energize the cable circuit andconnected transformers, and only three-poleswitches are used to connect the transformerto the cable circuit, delta, open-delta, orfloating-wye connections may be used forthe primary windings.

5. Consumer load connected to the cable-fedtransformer should not be used or relied onto prevent ferroresonance during single-poleswitching on the primary side of the distrib-ution transformer. If the load is too small, itwill not prevent overvoltages, yet may bedamaged by the resultant overvoltages. Withfloating-wye/delta transformer connections,badly unbalanced secondary load will preventferroresonance but cause high overvoltages bya different mechanism during single phasing.

6. Delta or ungrounded-wye primary windingscan be used with three-phase transformersor banks of single-phase transformers in24.9- and 34.5-kV UD systems without the

possibility of ferroresonance only if three-pole switches are used to energize and de-energize cable circuits and their connectedtransformers and three-pole switches areused at the HV terminals to connect thetransformer to the cable circuit. Single phas-ing, caused by conductor or jumper open-ing, may result in ferroresonance under lightload conditions.Cable-fed transformers with delta or un-

grounded-wye primary windings are not rec-ommended for use in new UD systems.

7. Delta or ungrounded-wye primary windingconnections should not be used with cable-fed, three-phase transformers or banks ofsingle-phase transformers in 12.47-, 24.9-,and 34.5-kV UD systems when single-poleswitching of cable circuits and connectedtransformers will be performed. The onlyexception to this recommendation is if thetransformer primary windings are connectedungrounded-wye and provisions are made atthe transformer to temporarily ground theneutral during single-pole switching operations.

8. Delta or ungrounded-wye connected primarywindings should not be used for three-phasetransformers or banks of three single-phasetransformers even when single-pole switchingwill be done only at the primary terminals ofthe transformer. The only exception to thisrecommendation is if the transformer primarywindings are connected ungrounded-wyeand provisions are made at the transformerto temporarily ground the neutral duringsingle-pole switching operations.

6


Anderson, P.H. Analysis of Faulted Power Systems.Ames, Iowa: Iowa State University Press, 1982.

Crann, L.B., and R.B. Flickinger. “Overvoltageson 14.4/24.9kV Rural Distribution Systems.” AIEETransactions (Power Apparatus and Systems) 73,part III (October 1954): 1208–1212.

DiPietro, J., and R.H. Hopkinson. “Ferroresonanceon Underground Feeders Having Several Trans-formers.” Southeastern Electric Exchange Engi-neering and Operating Meeting, New Orleans,La., April 26–27, 1976.

Feldman, J.M., and A.M. Hopkin. “A SimpleNonlinear Analysis of the Single-Phase Ferrores-onant Circuit.” Paper C 74 233-3, IEEE PES Win-ter Meeting, New York, N.Y., January 27, 1974.

Ferguson, J.S. “A Practical Look at Ferroreso-nance.” Missouri Valley Electric Association Engi-neering Conference, Kansas City, Mo., April17–19, 1968.

Gasal, J. “Prevent Overvoltage Failure of Ar-resters.” Electrical World (July 1986): 47.

Germany, N., S. Mastero, and J. Vroman. “Re-view of Ferroresonance Phenomena in High-Voltage Power System and Presentation of aVoltage Transformer Model for PredeterminingThem.” CIGRE Paper 33-18, August 21–29, 1974.

Hendrickson, P.E., I.B. Johnson, and N.R.Schultz. “Abnormal Voltage Conditions Producedby Open Conductors on Three-Phase CircuitsUsing Shunt Capacitors.” AIEE Transactions 72,part III (1953): 1183–1193.

Hopkinson, R.H. “Ferroresonance During Single-Phase Switching of Three-Phase DistributionTransformer Banks.” IEEE Transactions onPower Apparatus and Systems PAS84 (April1965): 289–293, discussion June 1965, 514–517.

Hopkinson, R.H. “Ferroresonant OvervoltageControl Based on TNA Tests on Three-PhaseDelta-Wye Transformer Banks.” IEEE Transac-tions on Power Apparatus and Systems PAS86,no. 10 (October 1967): 1258–1265.

Hopkinson, R.H. “Ferroresonant OvervoltageControl Based on TNA Tests on Three-PhaseWye-Delta Transformer Banks.” IEEE Transac-tions on Power Apparatus and Systems PAS87,no. 2 (February 1968): 352–361.

Locke, P. “Check Your Ferroresonance Conceptsat 34 kV.” Transmission and Distribution (April1978): 3239.

Millet, R.D., D.D. Mairs, and D.L. Stuehm. “TheAssessment and Mitigation Study of Ferroreso-nance on Grounded-Wye/Grounded-Wye Three-Phase Pad-Mounted Transformers.” Final Report:NRECA Energy Research Division, January 1990.

Pennsylvania Electric Company. “Field Investiga-tion of Ferroresonance on 20/34.5-kV Distribu-tion Three-Phase Transformer Banks.” PENELEC,October 14, 1964.

Rudenberg, R. Transient Performance of ElectricPower Systems. Cambridge, Mass.: The MITPress, May 1970.

Schultz, R.A. “Ferroresonance in DistributionTransformer Banks on 19.8/34.5 kV Systems.”Rocky Mountain Electric League Spring Confer-ence, Boulder, Colo., April 21, 1964.

Smith, D.R., S.R. Swanson, and J.D. Borst. “Over-voltages with Remotely Switched Cable-FedGrounded Wye-Wye Transformers.” IEEE Trans-actions on Power Apparatus and Systems PAS94,no. 5 (September/October 1975): 1843–1853.

Stoelting, H.O. “A Practical Approach to Ferrores-onance as Established by Tests.” Pacific CoastElectric Association Engineering and OperatingMeeting, San Francisco, Calif., March 4, 1966.

Walling, R.A. “Ferroresonance in Today’s Distribu-tion Systems.” Presentation to the Western Under-ground Committee, Palo Alto, Calif., May 2, 1991.

Walling, R.A. “Ferroresonance Guidelines forModern Transformer Applications.” Final Reportto the Distribution Systems Testing, Application,and Research (DSTAR) Consortium, July 1992.

6References

280 – Sect ion 6

Walling, R.A., K.D. Barker, T.M. Compton, andL.E. Zimmerman. “Ferroresonant Overvoltages inGrounded Wye-Wye Pad-Mounted Transformerswith Low-Loss Silicon-Steel Cores.” Presentationat the IEEE 1992 Summer Power Meeting.

Young, F.S., R.L. Schmid, and P.I. Fergestad. “ALaboratory Investigation of Ferroresonance inCable-Connected Transformers.” IEEE Transac-tions on Power Apparatus and Systems PAS-87,no. 5 (May 1968): 1240–1248.

6

Cathodic Protect ion Requirements – 281

Cathodic ProtectionRequirements7

Special Note

Introduction

In This Section:

With the 2006 transition to jacketed medium-voltage distribution-class cables, cathodic protec-tion is not generally needed in today’s applica-tions. With the older BCN cables (now not RUSaccepted), cathodic protection was a necessary

precaution to avoid corrosion on the exposedbare concentric neutrals in certain soil types.This section is being left in this manual as ahistorical reference for those situations inwhich BCN cables are still in operation.

Special Note

Introduction

What to Protect

Where to Protect

Types of Cathodic Protection Systems

Amount of Cathodic Protection

Cathodic Protection Design withGalvanic Anodes

Cathodic Protection Installationand Follow-Up

Calculation of Resistance to Ground


Cathodic protection is an effective and economi-cal means for avoiding underground corrosionin electrical grounding to ensure safe and reli-able operation of the electric system. Cathodicprotection is protection of the neutral, groundelectrodes, and other metal in contact with soilthrough the use of sacrificial anodes or rectifiersand impressed-current anodes.

Cathodic protection has become a necessityfor electric utilities because of the broad shift tounderground construction and the use of non-conducting materials. In the past, the electricneutral and ground wires were connected toburied steel piping, conduit, tanks, wells, andanchors at many locations. Copper grounds andcopper wires in soil received cathodic protectionat the expense of buried steel. The large extent

of buried steel, together with surface films onthe copper, caused the resulting corrosion ofsteel to be so slow that it was generally ignored.

Now, copper-jacketed ground rods and copperwires may be the only earth contact for safetyand electrical protection. With no steel connect-ed, the copper is vulnerable to corrosion becauseof variations in the soil and from ac voltagespresent on the neutral. Corrosion of copper inthese circumstances can result in loss of electri-cal protection, property damage, and hazards tooperating crews and the public.

This section explains, step by step, how todesign and install cathodic protection with sacri-ficial anodes, and how to recognize where suchprotection will be the most important.

282 – Sect ion 7

THE ELECTRIC NEUTRAL AND GROUNDSThe first requirement is to protect the electricneutral and grounds. The necessity for effectivegrounding and continuity of the neutral returnconductor should be obvious. Cathodic protec-tion is a cost-effective means for avoiding prob-lems in these areas.

7OTHER BURIED, GROUNDED METALBuried steel conduit, anchors, pipes, and well cas-ings are subject to corrosion when they are con-nected to the common neutral, particularly whenthe grounding is with copper materials. Cathodicprotection of the neutral and grounding system isneeded to avoid or control such corrosion.

Where to Protect Consider cathodic protection at the time of con-struction where any of the following apply:

• In new residential subdivisions with nonmetal-lic sewer lines, water lines, gas lines, andcopper-grounded electric facilities, where theonly buried metal connected to the neutral iscopper. Copper may corrode rapidly in thesesituations because of the mixing of soils dur-ing regrading and the absence of the cathodicprotection usually provided by buried steel.

• Along other routes with widely variable soilconditions that may result from differences interrain, soil moisture, drainage, and the pres-ence of contaminants such as ashes, coal,dumped refuse, or drainage from barnyardsor irrigated fields.

• At services from copper-grounded electric cir-cuits where steel pipes, tanks, or well casings

are vulnerable to accelerated corrosionbecause of the effects of dissimilar metals.

• At the ends of copper-grounded cable routesin very high-resistivity soils, where ac voltageson the neutral may cause accelerated corro-sion of buried copper (Zastrow, 1981).

• Near cathodically protected pipelines and inthe vicinity of rectifiers that supply dc forcathodic protection; also, near dc-poweredrailways and mining operations. Control ofcorrosion from external dc sources mayrequire special measures in addition to instal-lation of cathodic protection (Zastrow, 1979).

To understand underground corrosion andcorrosion-control measures, one must recognizethat the electric neutral and ground connectionsbehave as a dc circuit and must be treated as such.The electric neutral, ground electrodes, and otherburied metal components connected to them actas a huge galvanic cell. The more noble buriedmetal surfaces, usually copper, become cathodesand are protected against corrosion. The lessnoble metals, usually iron and steel, becomeanodes and are corroded (see Figure 7.1).

The electric grounding system may be in anarea of widely varying soil resistivity (see Figure7.2). Shaded areas on the map represent loca-tions of low-resistivity, corrosive soils. Metals incorrosive soil become anodes and corrode, where-as the metals in less-corrosive soil are protectedagainst corrosion. See Section 5 for a detaileddiscussion of soil electrical resistivity.

When both copper and steel are present invariable soils, as at a connection between an un-derground cable and pole line (see Figure 7.2),the steel anchor in corrosive soil becomes theanode and corrodes, whereas the copper in lesscorrosive soil is protected against corrosion. If

FIGURE 7.1: Dissimilar Metal Effects Between Buried MetalsConnected to the Neutral of an Electric Distribution Line.

Copper Grounds(Cathodes)

Copper Grounds(Cathodes)

CopperGrounds

Steel Pipe(Anode)

Irrigation Well(Anode)

Anchor(Anode)

Pole Line

Electron Flow

What to Protect


only buried copper is present, as may be truewith underground cables, the copper in corro-sive soils sacrifices itself to protect the copper inless corrosive soils.

7THE SIGNIFICANCE OF DC POTENTIALSUnderground corrosion occurs because of differ-ences between dc potentials of the buried metals,either because of dissimilar metals or because ofdifferences in soil.

Typical dc potentials of some common metalsand of carbon are shown in Table 7.1. The high-er (more negative) the dc potential, the morelikely the metal is to corrode when connected toother buried metals.

Potentials such as shown in Table 7.1 aremeasured with a high-resistance voltmeter andcopper-copper sulfate half cell (see Figure 7.3).

If two buried metals are connected, the onewith a higher negative potential is corrodedwhile the other is protected (see Figure 7.4).

A single buried metal, such as copper, cor-rodes in varying soils as shown in Figure 7.5.

SOIL RESISTIVITYInclude soil resistivity measurements as part of apreconstruction survey along each proposed un-derground cable route. At the same time, recordthe locations of pipeline crossings and other pos-sible dc sources that may cause cathodic protec-tion interference.

Soil resistivity is measured with a four-termi-nal ground test instrument, with four equallyspaced probes placed in a straight line (see Fig-ure 7.6). If measurements are made in the vicin-ity of a BCN cable or buried pipe, the probesshould be off to one side and at right angles tothe buried metal.

FIGURE 7.2: Electric System Map Shaded to Show Corrosive SoilLocations.

(A) Corrosive soils (B) Less corrosive soils

VoltmeterTo VoltmeterDetail of Half Cell

Copper Rod

Copper Sulfate Solution

Excess CrystalsPorous Plug

Half Cell

SoilSoil

Metal

B

A

BB

Material Potential, Volts*

Zinc -1.1

Iron -0.6 to -0.7

Copper 0 to -0.1

Carbon +0.2

* To a copper-copper sulfate half cell

TABLE 7.1: Typical DC Potentials in Soil.

Electron Flow Electron Flow

FIGURE 7.3: Measurement of Potential to a Copper-Copper SulfateHalf Cell.

Soil resistivity

measurements are

essential for success

in any corrosion

control effort.

SOIL AND TERRAIN FEATURESThe appearance of soil and the nature of the ter-rain often reveal locations of corrosive soils aswell as soils not likely to be corrosive. Swamps,

Recollections of

underground crews

about soil types may

be valuable.

284 – Sect ion 7

streams, and poorly drained areas indicate se-verely corrosive soils. Well-drained areas andpresence of carbonates (lime) usually indicatelocations of no significant corrosion.

The appearance of soils at cable depth maybe significant for the following reasons.

• Red clay is only mildly corrosive to buriedsteel. Red signifies the presence of iron oxide,indicating the presence of oxygen, which helpsform passive protective films on iron or steel.

• Blue or gray clay, sometimes mottled with white,is severely corrosive to both copper and steel.This usually dense clay is deficient in oxygenand associated with poorly drained soils.

• White alkali on the surface in dry areas, or lowlocations including marshes where drainage ispoor, represent corrosive soils. These may begood locations for sacrificial anodes.

7

FIGURE 7.4: Dissimilar Metal Effects Between Copper and Steel.

EXAMPLE 7.1: Measuring Earth Resistivity.

FIGURE 7.5: Dissimilar Soil Effects on Buried Copper Wires.

FIGURE 7.6: Measurement of Earth Resistivity with a Four-TerminalGround Tester.

Copper

Iron

Soil Soil

+ Ions

Electron Flow

Electron Flow

P1 P2

C1 C2

A = Distance between probes Cable

A A A

IonsIons

Soil

CorrodingProtectedIron

–0.06V–0.05V

Copper

Bare-NeutralCable

Arrows represent the flow of electrons in connecting wires and movement of positive ions inthe soil. To show “conventional flow” (movement of positive charge), reverse the arrows thatrepresent electron flow.

In Figure 7.6, if A = 5.2 feet, multiply the meter readingby 10 to find earth resistivity in ohm-m. For 5.2-footspacing, if the meter reads R = 2.4 ohms, soil resis-tivity is 24 ohm-m. For 10.4-foot spacing, multiply themeter reading by 20.

Additional information about soil resistivity measure-ments and grounding is given in Section 5 of this manual.

CORROSION EXPERIENCEMake use of maintenance and replacementrecords and recollections of underground crewsto identify the areas of most probable corrosion.Note the locations and ages of components(cable neutrals, ground wires, ground rods, andanchor assemblies) as well as their condition atthe time of observed deterioration or failure.

Anodic (Corroding) Area Cathodic (Protected) Area


7Cathodic protection may be provided by sacrifi-cial anodes of magnesium or zinc, or by recti-fiers and impressed-current anodes.

RECTIFIER SYSTEMSRectifier systems are used where there is a needfor higher output voltages and/or currents thangalvanic anodes can provide. Rectifiers use anac source to apply a negative potential to theprotected structure and return the dc to earthby means of one or more impressed-currentanodes. Rectifier systems are more exacting intheir requirements for design and regular atten-tion to maintenance. A rectifier system mayeither prevent or cause corrosion problems,depending on design and the physical locationof the anode or anode bed.

Adjustable rectifiers, along with impressed-current anodes, are used for protecting large un-derground structures such as pipelines, storagetanks, and wells in oil fields. They may be themost economical means for protecting groundingsystems at generating stations, substations, andmajor industrial facilities. These rectifier systemsshould be designed and installed by individuals

of proven competence who have experiencewith such installations. Special attention must begiven to the location of anodes and adjustmentof the rectifiers to avoid serious damage to thegrounding system or other nearby facilities.

Small constant-current rectifier units are usedto provide more current output than is availablefrom sacrificial anodes. They are usually installedat pad-mounted equipment where the anodescan be buried at minimum cost with a minimumof digging. They have been suggested for retro-fitting along existing BCN underground cables.Results have been mixed in terms of reliabilityand service life, particularly in soils with veryhigh resistivities. Use of these units should belimited at first in order to gain experience.

SACRIFICIAL ANODE SYSTEMSSacrificial anodes are widely used for cathodicprotection on electric distribution facilities forreasons of cost and the minimum maintenancerequired. The balance of this section will beaddressed to cathodic protection by means ofsacrificial anodes.

Sacrificial anodes make use of dissimilar metaleffects to protect buried metals against corro-sion. For example, if steel is corroding becauseof a connection to copper (see Figure 7.4), azinc anode can be added to provide protection(see Figure 7.7).

The potentials in Figure 7.7 show the effect ofsurface films, which have the effect of reducingthe amount of current required for cathodic pro-tection. The potentials of the individual metals insoil for copper, iron, and zinc are 0, -0.6, and -1.1volts, respectively (see Table 7.1). Note: Whenthey are connected together, the potential thatresults is more negative than the average of theindividual metal potentials. For the copper-ironcouple, the resulting potential is -0.4 instead of-0.3 volt. The potential of the copper-iron-zinccombination is -0.8 volt, even though the averageof the three is -0.57 volt. The difference is due tofilms that usually form on cathodic surfaces.

FIGURE 7.7: Potentials of a Copper-Steel Couple Before and AfterConnecting a Zinc Anode.

+Ions Positive Ions

ElectronFlow

Electrons

Zinc

–0.8V–0.4V –1.1V

Copper(Protected)

Iron(Corroding)

Zinc(Corroding)

Copper(Protected)

Iron

Types of CathodicProtectionSystems

286 – Sect ion 7

The cathodic protection should cause enoughcurrent flow to make the dc neutral potentialsufficiently negative to prevent corrosion. Thepotential selected for providing protection is im-portant, as the cost of cathodic protection in-creases directly with the shift in dc potential tobe achieved. Experience in the cooperative’sservice area is the best guide for deciding onpotentials that are effective yet practical.

Steel or iron in soil is usually regarded as pro-tected against corrosion at potentials of -0.85 volt ormore negative. In most soils, however, steel an-chor assemblies and ground rods are lasting morethan 25 years at potentials such as -0.5 to -0.6 volt.

Buried copper is generally free of corrosion atpotentials of -0.1 to -0.25 volt, but may corrodeat more negative potentials in the presence of acvoltages (Zastrow, 1981).

Examples drawn from RUS experience aregiven in Table 7.2. With these potentials as aguide, cathodic protection is designed to maintaindc neutral potentials equal to or more negative

7Amount ofCathodicProtection

than those shown in Table 7.2. More negativepotentials provide a greater margin of protec-tion; less negative potentials increase the proba-bility of underground corrosion problems.

The potentials in Table 7.2 are intended to pro-vide a starting point until experience is gained inselecting potentials to provide the desired degreeof protection at an acceptable cost. Experience inthe service area, interpreted in light of “as found”dc potentials, should be helpful for deciding onthe ones to be used for cathodic protection design.

Noncorrosive soils are defined as those in whichsteel ground rods and steel anchor assemblies,pipes, and wells connected to a copper-groundedneutral lasted for 20 years or more without sig-nificant losses resulting from underground corro-sion. Anchor assemblies bonded to pole lineneutrals would not have experienced difficultybefore underground construction, with first fail-ures after 20 years or more. No undergroundcorrosion of copper would have been noticedbefore the installation of BCN underground cables.

Corrosive soils are those in which significantnumbers of anchor rods bonded to a coppergrounded neutral failed within 15 years after in-stallation, or in which significant corrosion ofburied copper has been experienced.

At locations of steel wells, tanks, pipes, andconduit, the design should avoid any objection-able flow of dc in service neutrals.

At connections to extensive copper-groundedfacilities, the dc potentials are strongly influ-enced by “as-found” conditions. To achieve amore negative cable neutral potential at such lo-cations, the owner may need to provide cathodicprotection for the “foreign” grounding system.Or, as an alternative, the owner should installanodes at locations of grounds along the newcable so that, after a mile or so, the desiredpotentials will be achieved.

Cathodic protection designs, and these specifi-cations, are only approximate because of widevariations in soil properties, variable effects ofpolarization films, and uncertainties about thecharacteristics and extent of buried metal struc-tures connected to the neutral. Even so, proce-dures such as these are necessary to avoid thehigh cost of ineffective installations and wasted,improperly located anodes.

Conditions Potential (volts dc)**

Along jacketed cables***

In noncorrosive soils -0.7

In corrosive soil areas -0.85

At locations of grounded steel wells, tanks, conduit -0.85

Along BCN cables


In corrosive soil areas -0.4 to -0.7

At locations of grounded steel wells, tanks, conduit -0.85

At cable terminal poles


In corrosive soil areas -0.85

At connections to extensive copper-grounded facilities -0.4

* From long-term personal experience on electric systems financed by RUS.** Volts to a copper-copper sulfate half cell.***There is a lack of experience with protection of cables with semiconducting jackets.

Use the same values as for cables with insulating jackets, if these levels are practical;otherwise, try, as a minimum, to achieve those indicated for BCN cables.

TABLE 7.2: Suggested DC Potentials for Cathodic Protection.*

FIGURE 7.8: Equivalent Circuit for a Galvanic Anode Connected to the Electric Neutral.


A cathodic protection system is actually a dc cir-cuit (see Figure 7.8). The anode is the voltagesource, ground connections (metals buried insoil) are the load, and the neutral conductor andground wires provide the connections to theload. The current return path is through the soil.(See Figures 7.4, 7.5, and 7.7.)

The object of cathodic protection is to shiftthe dc potential of the neutral to a sufficientlynegative value to control or stop corrosion.

Cathodic protection design requires at leastfive steps:

STEP 1: Calculate the neutral resistance toground.

STEP 2: Decide on the shift in dc neutralpotential that will be necessary foradequate control of corrosion.

STEP 3: Calculate the anode output currentrequired.

STEP 4: Select the anode types, sizes, andnumbers.

STEP 5: Decide on approximate locations foranodes along the cable.

These steps will now be described in detailfor Jacketed Cables and Overhead Pole Lines.For the following other types of situations—Protection of Bare Concentric Neutral Cables,Cables with Conducting (Semicon) Jackets,

7CathodicProtection Designwith GalvanicAnodes

Ea = Open circuit anode potential,the dc potential the anodewould assume if not connectedto anything else

En = DC neutral potentialRn = Resistance-to-earth of the

neutral and groundsRa = Anode resistanceRw = Resistance of the anode lead

Cables in Conduit, Large Power Users, andConnections to Other Facilities—only addi-tional factors to be considered are included.

JACKETED CABLES AND OVERHEAD POLE LINESA jacketed underground cable, with an insulat-ing jacket over the neutral wires, is similar to apole line with regard to grounding and cathodicprotection design. In both, most of the ground-ing is by means of driven ground rods along theline and on consumers’ premises. Additionalgrounding is provided by other buried metal(conduit, pipes, wells, tanks, and pole anchorassemblies) connected to the common neutraland in contact with the soil.

STEP 1: Calculate the Neutral Resistanceand Conductance to GroundThe discussions that follow refer to conductance(the reciprocal of resistance) instead of resistanceto avoid the cumbersome formulas that are nec-essary for finding the equivalent of resistances inparallel. Conductances of individual grounds inparallel can be combined by simple addition ormultiplication.

Note: There is a great difference between thevalue of resistance or conductance to ground perunit length (per mile or kft) of neutral and thevalue for the complete neutral, which usually hasa resistance to ground of a fraction of one ohm.

Rw

En

Rn

Ea

Ra

288 – Sect ion 7

7EXAMPLE 7.2: Calculating the Neutral Conductance to Ground Per 1,000 Feet of Cable.

Estimate the number of ground rods per 1,000 feet (kft) along the line andon consumers’ premises. If soil resistivities vary substantially, indicateseparately the numbers of ground rods in the lower or higher resistivityareas. (Note that this calculation is not precise!) If pole line anchors areincluded, assume that each is equivalent to half a ground rod.

Determine the conductivity to ground from the numbers of drivengrounds and the information in Table 7.3.

Equations for calculating the values given in Table 7.3 are explained laterin the subsection, Calculation of Resistance to Ground.

Assume that this is an underground cable with an insulating jacket overthe neutral wires. There are, on average, 15 driven grounds per mile, in-cluding those on consumers’ premises. One-third of them are in soilswith resistivities of approximately 20 ohm-m, and two-thirds are in high-resistivity soils, 500 ohm-m and higher. Calculate the conductance toground per mile of cable:

• If grounding is with 5/8-in. × 8-ft rods, and• If grounding is with 3/4-in. × 8-ft rods.

The conductance per eight-foot ground rod (Table 7.3) is as follows:

In 20 ohm-m soil,5/8-in. rods = 0.125 siemens3/4-in. rods = 0.129 siemens

In 500 ohm-m soil,5/8-in. rods = 0.0050 siemens3/4-in. rods = 0.0052 siemens

Conductance to ground per mile of cable neutral:

For 5/8-in. rods,5 rods in 20 ohm-m soil: 5 × 0.125 = 0.625 siemens10 rods in 500 ohm-m soil: 10 × 0.005 = 0.050 siemens

Sum: 0.675 siemens

For 3/4-in. rods,5 rods in 20 ohm-m soil: 5 × 0.129 = 0.645 siemens10 rods in 500 ohm-m soil: 10 × 0.0052 = 0.052 siemens

Sum: 0.697 siemens

Soil Resistivity (ohm-m*)Ground 5 10 15 20 100 500 2,500Rod Size (Resistance, ohms, and conductance, siemens)

5/8 in. x 8 ft.

Resistance 1.995 3.990 5.985 7.981 39.90 199.5 997.6

Conductance 0.5013 0.2506 0.1671 0.1253 0.0251 0.00501 0.00100

3/4 in. x 8 ft.

Resistance 1.936 3.871 5.807 7.743 38.71 193.6 967.9

Conductance 0.5168 0.258 3.1722 0.1291 0.0258 0.00517 0.00133

3/4 in. x 10 ft.

Resistance 1.607 3.214 4.821 6.427 32.14 160.7 803.4

Conductance 0.6223 0.3111 0.2074 0.1556 0.0311 0.00623 0.001245

* For resistivity in ohm-cm, multiply by 100.

TABLE 7.3: Calculated Resistance and Conductance to Ground of IndividualGround Rods as Related to Soil Resistivity.


a compromise between an “ideal” level of protec-tion desired and cost of the cathodic protection.See Example 7.3.

STEP 3: Calculate the Anode OutputCurrent RequiredCalculate the anode output current requiredfrom Ohm’s law, I = V × G, where V is the shiftin potential to be achieved and G is the neutralconductance (reciprocal of resistance), insiemens, to ground. See Example 7.4.

STEP 4: Select Anode Types, Sizes,and NumbersDecide on the anode types and sizes needed.The selections of anodes and their locations arelikely to determine the effectiveness—and in-deed, the success or failure—of the cathodicprotection installation. The selections will de-pend on soil resistivities at anode locations andon the anode characteristics that determine out-put, service life, and installed cost.

Table 7.5 provides information about standardsizes and types of anodes, as follows:

• Column (a), anode weight and the backfillpackage size, for calculating resistance.

• Column (c), anode resistance in soil with theresistivity shown in column (b).

• Column (d), the current output and estimatedlife when protecting the neutral at each offour potentials shown. The driving potentialfor each output calculation is equal to thesolution potential indicated for each anodematerial less the structure potential.

The estimated lives in Table 7.5 are based onampere years’ output of magnesium and zincanodes as follows:

Magnesium anodes:17- and 20-lb. sizes, 1.0 ampere year32-lb. size, 2.0 ampere years48- and 50-lb. sizes, 3.0 ampere years

Zinc anodes:30-lb. size, 1.2 ampere years60-lb. size, 2.4 ampere years

7

EXAMPLE 7.3: Determining Required Shift in Potential.

Assume, for this example, that the selected neutral potential is -0.7 volt, to minimizeprobable corrosion of buried steel connected to the neutrals along the cable route.The shift in potential required is the difference between -0.7 volt and the potentialthe neutral would have without cathodic protection.

The potential of a neutral without cathodic protection is determined by ground rodsand other buried, connected metals. Potentials that are likely, with no cathodic pro-tection, are -0.1 volt if all grounding is with copper and -0.6 volt if grounding is withsteel disregarding the short-term effects of galvanizing (Table 7.4).

Buried Metal or Material Typical DC Potential (volts)

Zinc or new galvanized steel –1.1

Old steel or iron –0.5 to –0.6

Copper 0 to –0.1

Carbon (in insulation shield or jacket) +0.2

TABLE 7.4: Potentials to a Copper-Copper Sulfate Half Cell.

The shift in neutral potential needed to achieve a neutral potential of –0.7 volt is –0.1 voltfor steel and –0.6 volt for copper.

EXAMPLE 7.4: Calculating Required Anode Output Current.

With copper-jacketed ground rods,

With steel ground rods,

I = 0.6 × 0.675 = 0.405 A (405 milliamperes [mA]) per mile

I = 0.1 × 0.697 = 0.0697 A (70 mA) per mile

STEP 2: Determine the Shift inPotential RequiredTo determine the dc shift in neutral potential tobe achieved by cathodic protection, select theneutral potential needed for adequate protection(Table 7.1 or 7.2). The selection will usually be

290 – Sect ion 7

7Horizontal Anodes at 6-Foot Depth

(a) (b)* (c) (d)Anode Current Output and Estimated Life for Structure Potential (volts)

Nominal Package Soil Resistivity Anode Resistance –0.3 –0.5 –0.7 –0.85Weight (lb.) Size (in.) (ohm-m**) (ohms) (mA) (yrs) (mA) (yrs) (mA) (yrs) (mA) (yrs)

Standard Magnesium (Solution Potential = –1.55V)

17 22 × 7 2 9 139 7 117 9 94 11 77 13

50 23 54 19 46 22 37 28 30 33

100 46 27 37 23 ! 18 ! 15 !

32 26 × 8.5 20 7.7 162 12 136 15 110 18 91 22

50 19 66 30 55 36 45 ! 37 !

100 38 33 60 28 ! 22 ! 18 !

50 22 × 10 20 7.1 176 17 147 20 120 25 99 31

50 18 69 43 58 ! 47 ! 39 !

High-Potential Magnesium (Solution Potential = 1.73V)

17 38 × 6 50 19 75 13 65 15 54 19 46 22

100 39 37 32 32 23 26 38 23 43

200 78 18 ! 16 ! 13 ! 11 !

20 64 × 5 100 31 46 22 40 25 33 30 28 36

200 62 23 44 20 ! 17 ! 14 !

500 154 9 ! 8 ! 7 ! 6 !

48 34 × 8 20 7.2 199 15 171 18 143 21 122 25

50 18 79 38 68 44 57 ! 49 !

Zinc (Solution Potential = –1.10V)

30 66 × 6 20 5.7 140 8.5 105 11 70 17 44 27

30 8.6 93 13 70 29 47 26 29 41

50 14 57 21 43 28 29 41 18 !

60 66 × 6 10 2.9 275 8.7 207 12 138 17 86 28

20 5.7 140 17 105 23 70 34 44 !

30 8.6 93 26 70 34 47 ! 20 !

! = Not meaningful; exceeds 45 years.* At anode depth.** To express in ohm-cm, multiply by 100.

TABLE 7.5: Sacrificial Anode Resistance, Output Current, and Estimated Life.


soil resistivity locations available, but use discretionregarding maximum distances between anodes.

Give special attention to locations where thenewly installed cable is connected to other facili-ties (particularly copper-grounded stations), oldBCN cables, and loads such as irrigation wellswith unusual amounts of grounded metal sur-rounded by irrigated soil areas.

PROTECTION OF BARE CONCENTRICNEUTRAL CABLESMost of the grounding of BCN cable is by directcontact with the concentric neutral wires. Addi-tional grounding is by means of driven groundrods and by other buried metal connected to theneutral and ground wires.

Neutral Conductance to GroundTable 7.6 shows calculated conductances toground of BCN neutrals with effective diametersas indicated. The conductances are inverselyproportional to soil resistivity, so values in soilswith other resistivities can be determined with-out the need for detailed calculations.

The effective diameter in Table 7.6 is the di-ameter of the individual cable, or of the groupof cables in a multiphase circuit. If cables are ina flat or irregular configuration, an estimateshould be made of an equivalent circle thatwould enclose the conductor cross sections.

Soil resistivity is the most important variable ofall, as is shown in Table 7.6. Yet soil resistivity dataare subject to considerable error because of practi-cal limitations of field surveys, seasonal tempera-ture variations, and changes in soil moisture.

How accurate can the cooperative afford tobe? Do the following:

1. Obtain the best soil resistivity data at cabledepth that time and resources allow. Particu-larly, find the approximate boundaries oflowest and highest resistivity areas if variationsare in the range of five to one or greater.Learn to identify the extremes from the na-ture of terrain, soil appearance, and vegeta-tion. The rate of progress in field surveys isslow at first but will increase with experience.

2. To calculate the neutral conductance toground if there are wide variations in soil re-sistivity, do the following:

7EXAMPLE 7.5: Selecting Anode Types, Sizes, and Numbers.

See Table 7.5, in the columns for a 0.7-volt structure potential, to find the anodes thatmight be selected, calculated current outputs, and estimated lives:

In 20 ohm-m soil: Standard magnesium, 32-lb., 110 mA, 18 yearsHigh-potential magnesium, 48-lb., 143 mA, 21 yearsZinc, 30-lb., 70 mA, 17 yearsZinc, 60-lb., 70 mA, 34 years

In 500 ohm-m soil: High-potential magnesium, 20-lb., 7 mA, the anode life willexceed 45 years.

For copper-grounded cable, the 405 mA required for each mile can be provided withfour 32-lb. standard magnesium anodes (440 mA), or three 48-lb. high-potentialmagnesium anodes (429 mA), or six zinc anodes (420 mA), if they can be locatedin 20 ohm-m soil.

For steel-grounded cable, the 70 mA required can be provided with one zinc anodeper mile, installed in 20 ohm-m soil. Prior experience with steel-grounded pole lines,if available, may show that little cathodic protection is needed for cables with insu-lating jackets and galvanized steel ground rods.

Soil Effective Diameter (inches)Resistivity 1.00 2.00 4.00 8.00 12.00(ohm-m) (siemens per 1,000 feet of cable)

5 23.03 24.03 25.12 26.32 27.07

10 11.51 12.01 12.56 13.16 13.54

25 4.61 4.81 5.02 5.26 5.41

50 2.30 2.40 2.51 2.63 2.71

100 1.15 1.20 1.26 1.32 1.35

150 0.768 0.801 0.837 0.877 0.902

500 0.230 0.240 0.251 0.263 0.271

1,500 0.077 0.080 0.084 0.088 0.090

7,500 0.015 0.016 0.017 0.018 0.018

* For method of calculating, see information later in this section.

TABLE 7.6. Conductance to Ground of BCNs with Effective Diametersas Indicated.*

STEP 5: Decide on Approximate AnodeLocations Along the RouteDecide on approximate anode locations along theroute, and also the kinds of anodes, using soilresistivity profiles obtained during preconstructionsurveys. Take maximum advantage of the lowest

292 – Sect ion 7

a. Estimate the proportion of cable in each re-sistivity range as suggested in Example 7.6.

b. Calculate the conductance separately forcables in each resistivity range and addthem together to obtain the total.

3. Locate anodes of suitable size and type inthe lowest resistivity soil locations availableat reasonable intervals and in numbers suffi-cient to provide the total output needed.

4. Recognize as normal the wide seasonal vari-ations in soil resistivity that follow variationsin temperature and soil moisture. A sacrificialanode system is largely self-adjusting, withanode outputs and current requirementsgoing up and down together.

Concerning “accuracy,” recognize that resultsfrom a first installation are likely to miss the de-sign objective, in terms of potential shift achieved,by a considerable margin. Reliability of designestimates will improve with experience.

Shift in Neutral Potential RequiredFrom Table 7.1 or 7.2, select the potential thatshould be achieved by cathodic protection. Theselected potential might be -0.2 or -0.3 volts to acopper-copper sulfate half cell to protect copperconcentric neutral wires and grounds, or it might be-0.7 volts (or even -0.85 volts in corrosive soils) toprotect anchor rods and other buried steel connect-ed to the neutral. The level of protection selectedmakes a great difference in the cost of cathodicprotection, particularly where grounding is main-ly by means of copper in contact with the soil.

Anode Output Current and Anodes RequiredThe required anode output current per mile ofcable, to achieve the desired potentials, is givenby Equation 7.1. See Example 7.8.

CABLES WITH CONDUCTING(SEMICON) JACKETSCables with a conducting (semiconducting) jacketover the concentric neutral wires provide conduc-tivity to surrounding earth through the jacket inaddition to that provided by the metallic grounds.Additional cathodic projection capacity will beneeded to accommodate the conductivity effectof the jacket. The amount of additional cathodic

7EXAMPLE 7.6: Estimating Neutral Conductance to Ground of BCN Cable.

EXAMPLE 7.7: Determining Required Shift in Neutral Potential.

Assume a single-phase one-inch-diameter cable installed with one-third of its lengthin soils with resistivities on the order of 20 ohm-m and two-thirds of its length in soilwith resistivities of 400 to 1,000 ohm-m (500 ohm-m average).

From Table 7.6, conductance to ground of one-inch-diameter cable neutrals in 20ohm-m soil is 5.75 (half of 11.51) siemens per kft, and for cables in 500 ohm-m soil,0.23 siemens per kft.

Following the above proportions, a mile of BCN cable will have 1,760 ft (1.76 kft) ofits length in 20 ohm-m soils and 3.52 kft in the 400 to 1,000 ohm-m soils. Theneutral conductance to ground per mile of cable is as follows:

In 20 ohm-m soil, 5.75 × 1.76 = 10.12 siemensIn 500 ohm-m soil, 0.23 × 3.52 = 0.81 siemens

Total per mile = 10.93 siemens

Conductance to ground of driven rods along the cable, based on 15 per mile, is asfollows:

For copper rods, 5/8 in. × 8 ft,

In 20 ohm-m soil, 5 × 0.125 = 0.625 siemensIn 500 ohm-m soil, 10 × 0.0052 = 0.050 siemens

Sum = 0.675 siemens

For steel rods, 3/4 in. × 8 ft,

In 20 ohm-m soil, 5 × 0.129 = 0.645 siemensIn 500 ohm-m soil, 10 × 0.0052 = 0.052 siemens

Sum = 0.697 siemens

Note that more than 90 percent of the conductance to ground—and, therefore,most of the need for cathodic protection—is in the 20 ohm-m soil.

Equation 7.1

I = E × G

where: I = Current, in amperesE = DC potential shift, in voltsG = Conductance, in siemens

For this example, assume that the selected potential is -0.5 volts to a copper-coppersulfate half cell. As -0.1 volts is the probable potential of copper without cathodicprotection (Table 7.4), the shift in potential needed is -0.4 volts for copper and zerofor steel rods.


BCN cables must not be installed in direct-buried,nonmetallic conduit. Cables in conduit are muchmore vulnerable to underground corrosion thanare cables in soil. Variations in the environmentare extreme, going from soil to mixed air andsoil, into a humid atmosphere and possiblewater and then back into soil.

Conduit made of nonconducting materialpresents an insulating barrier around the cableso that cathodic protection from sources outsidecannot reach the cables inside. Steel conduit, onthe other hand, tends to sacrifice itself to protectbare copper neutral wires inside.

If BCN cables must be inside nonmetallic con-duit, a length of zinc ribbon anode should be pulledin with the cables and the core wire connected tothe cable neutrals at a splice at one or both ends.

For new construction, cables with insulatingjackets should be installed inside conduit.

LARGE POWER USERSThe grounds at a large power load, such as anindustrial grounding system or a center-pivot irri-gation well, may present a resistance to groundthat is low compared with that of the electricneutral at that location. Such a ground has a dcpotential that is not readily changed unless theowner installs cathodic protection in addition tothat along the electric line. Two alternative ap-proaches to consider are as follows:

1. Encourage the owner to install cathodicprotection.

2. Install additional anodes at grounding loca-tions nearby. The anodes provide a zone ofprotection for individual grounds and anchorassemblies, some protection to the consumer-owned grounds, and, over a distance alongthe line, bring the neutral to the desiredpotential.

CONNECTIONS TO OTHER FACILITIESInstall additional cathodic protection where anew cable is connected to an existing BCN cableor a copper-grounded substation. Follow proce-dures as for large power loads. Or install ca-thodic protection for the existing station or otherfacility at the time the new cable is installed.(See information later in this section.)

7EXAMPLE 7.8: Determining Output Current and Anodes Required.

Using the assumptions of Examples 7.6 and 7.7, determine the anode output currentand anodes required.

With copper-jacketed ground rods, the potential shift required is –0.4 volts for BCNwires and the ground rods.

Conductance to ground:

BCN wires = 10.93 siemens, as in Example 7.6Ground rods = 0.68 siemens

Sum = 11.61 siemens

Output current required for –0.4 volt shift:

I = 11.61 × 0.4 = 4.644 A (4,644 mA) per mile

I = 10.93 × 0.4 = 4.372 A (4,372 mA) per mile

With steel ground rods, the potential shift required is –0.5 volts for the BCN wiresand zero for steel ground rods:

Output current required:

See Table 7.5, in the columns for a –0.5 volt structure potential, to find the anodesthat might be selected, calculated current outputs, and estimated lives:

In 20 ohm-m soil: Standard magnesium, 50-lb., 147 mA, 20 yearsHigh-potential magnesium, 48-lb., 171 mA, 18 yearsZinc, 60-lb., 105 mA, 23 years

In 500 ohm-m soil: High-potential magnesium, 20-lb., 8 mA, the lifeof the anode will exceed 45 years.

If all anodes can be installed in 20 ohm-m soil, the numbers needed are as follows:

For 4,644 mA per mile: 32 per mile of 50-lb. standard magnesium (4,704 mA), or27 of 48-lb. high-potential magnesium (4,617 mA), or44 of 60-lb. zinc (4,620 mA).

For 4,372 mA per mile: 30 per mile of 50-lb. standard magnesium (4,410 mA), or26 of 48-lb. high-potential magnesium (4,446 mA), or42 of 60-lb. zinc (4,410 mA).

protection capacity will be dependent on thevolume resistivity of the jacket and the neutralconfiguration. It also may depend on the pres-ence of ac voltages (Zastrow, 1981).

CABLES IN CONDUITVirtually all cooperatives now use jacketed cable.However, if the cooperative still uses BCN cables,

294 – Sect ion 7

Making a diligent effort at cathodic protectiondesign, as discussed in the previous subsection,will be wasted effort and expense without thesame diligent effort in the actual installation ofthe cathodic protection. Particular attentionshould be paid to the following:

• Where the anodes are installed along the route,• The location of the individual cathodic pro-

tection installations relative to the protectedequipment,

• How the cathodic protection should beinstalled, and

• How the cathodic protection is connected tothe equipment.

In addition, determining the long-term perfor-mance of the cathodic protection requires ameans to monitor the performance.

After the preliminary cathodic protection re-quirements have been determined and the ap-propriate spacing calculated, the practical as-pects of locating this cathodic protection comeinto play. Spacing the cathodicprotection equally along theroute without regard to soilconditions, existing equipmentlocations, and so on should beavoided at all costs. Cathodicprotection installed at equaldistances along the route iswasteful and expensive andwill generally not provide thebest protection. Cathodic pro-tection should be adjusted inaccordance with the following (in priority order):

• Known Corrosion Locations. If the existingequipment is corroding at a particular loca-tion, it is a good assumption that the cathodicprotection will corrode (i.e., protect) at thesame location.

• Soil Resistivity. As discussed in the previoussubsection, the cathodic protection output isgreater in lower soil resistivity areas. Conse-quently, reasonable effort should be made tolocate the cathodic protection in these areas.

• Existing Equipment. Because above-groundconnections can be completed more easily at

7CathodicProtectionInstallation andFollow-Up

existing equipment, the cathodic protectionshould be further adjusted to those locationsas long as they are also near existing corro-sion areas and/or lower soil resistivity areas.

• Banking Anodes. A final adjustment may bemade to the cathodic protection design tolocate the greatest amount of cathodic protec-tion at those locations that meet the abovecriteria. This adjustment, of course, needs tobe tempered by the fact that better overallprotection may be provided by cathodic pro-tection distributed along the route rather thanlumped together at one or more locations.

After cathodic protection locations are deter-mined along a particular route, the same effortmust continue relative to positioning the ca-thodic protection with respect to the protectedequipment (such as cable) and how it is installed.As discussed in the cathodic protection designsubsection, the anode output is dependent onthe soil resistivity (the resistance between theanode and protected equipment) and the anode

lead length. Consequently, theposition of cathodic protectionis a compromise betweenthese two elements. In addi-tion, practical considerationsconcerning easements and theexpense to trench in cathodicprotection conductors have tobe considered.On the one hand, installing

anodes far from the cable willprotect the greatest length of

cable. On the other hand, the protection level isreduced and the existing easements and expensemay not permit installation of cathodic protectiona greater distance away from the cable. As a prac-tical matter, cathodic protection should be located10 to 50 feet from the protected equipment with25 feet as a practical compromise (see Figure 7.9).

Anodes can be installed either vertically in au-gured holes with a shallow trench to the pro-tected equipment, or horizontally in a trench.Either method will provide similar protection re-sults. The method used is generally dependent onthe equipment available and personal preference.In either case, the anode should be installed

Consider soil

condition, equipment

locations, and so

on when spacing

cathodic protection.


• Do not use the anode lead to install the anode.A disconnection may render the anode useless.

• To improve anode performance, distribute theanode backfill to surround the anode.

• In horizontal installations, turn the anode paral-lel to the cable or with the anode lead connec-tion furthest from the cable. Doing so will re-duce the possibility of the anode corrosiondisconnecting itself, although this is unlikely.

Anode connections to the neutral are often acompromise. In all cases, the connection to theneutral should be with the best connection (com-pression, if possible). It is relatively easy to com-plete a compression connection at above-groundlocations and when completing the connectionon newly installed cable. Existing cable that hasbeen in the ground a number of years makes theuse of compression connections difficult, if notimpossible. In these cases, the use of RUS-ap-proved connectors should be considered (seeFigure 7.10). In all connections below ground,the concentric neutrals should be thoroughlycleaned and the connection sealed to the extentpossible to reduce exposure to soil moisture.

In the years after the cathodic protection is in-stalled, it will be necessary to determine whetherthe cathodic protection is still operating and pro-viding the necessary protection levels. Determi-nation of continuing anode effectiveness is facili-tated by the installation of test stations along theroute. It is not necessary to install test stations atall cathodic protection locations. Test stationsshould be installed to provide a representativesample of the cathodic protection. For example,if a number of cathodic protection locations arein similar soil along the route, only one or twotest stations are necessary. This is based on theassumption that whatever happens at each loca-tion is similar. Of course, test stations adjacent toor inside existing equipment are preferred.

There are many commercially available teststations in either freestanding or flush-mountmodels. Freestanding models are much easier tofind in rough terrain but may not be aestheticallypleasing if installed in someone’s front yard. It isrecommended that the anode and neutral beconnected through a 0.1-ohm shunt resistor attest stations to facilitate testing without discon-nection in the future (see Figure 7.11).

7

FIGURE 7.9: Anode Positioning.

FIGURE 7.10. Anode Connector.

FIGURE 7.11. Test Station Connector.

with its entire length below (one-foot minimum)the protected equipment, which will put theanode generally in more moist soil and will givemaximum output. A few guidelines relative tothe actual installation should be observed:

Roadway

Ditch

Anode Possible LeadRoutes

10-Ft Minimum(25 Ft Preferred)

Hose Clamp-Type Connector

HoseClamp

NeopreneCushion

ConcentricNeutrals

Cable

Tinned CopperStrapCable

AnodeLead

Anode Lead

1

2

3

0.01-ohm Shunt

Leads toEquipment/Cable

Threaded Post

Cable

296 – Sect ion 7

The calculation of resistance to ground for pur-poses of cathodic protection is different fromthe calculation of ground resistance for purposesof lightning protection as discussed elsewhere inthis publication. A search of literature on calcu-lations of resistance to ground reveals that allseem to come from one primary source. Thiscalculation method applies to the resistance ofground rods, buried pipes and conductors, and

7Calculation ofResistance toGround

Equation 7.2

where: R = resistance, in ohmsρ = soil resistivity, in ohm-cm (ohm-m × 100)L = half the length, in cm (the wire length is 2L cm)a = wire radius, in cms = twice the depth, in cm (the depth is s/2)

R = In ...+ Inρ4πL

4La

– 2 +4Ls

–s2L

+s2

16L2s4

512L4

anodes for cathodic protection. The source is awork published in 1936 by H.B. Dwight entitledCalculation of Resistances to Ground. Dwightgives equations for resistance to ground of along-buried cylinder (wire, pipe, or BCN cable),a short buried cylinder (anode), and a verticalrod or cylinder.

The resistance of a long horizontal wire orcylinder buried in soil is given by Equation 7.2.(The conductances to ground of BCN cables,Table 7.6, are calculated by use of Equation 7.2.)

See Equation 5.13 for an equivalent expres-sion using more conventional measurements.

The resistance of a short wire (or cylinder) ata depth greater than its length is given by Equa-tion 7.3. (The resistances of sacrificial anodes,Table 7.5, are calculated by use of Equation 7.3.)

The resistance of a vertical rod is given byEquation 7.4. (The resistance and conductanceto ground of driven ground rods, Table 7.3, arecalculated by use of Equation 7.4.)

Equation 7.3

where: R = resistance, in ohmsρ = soil resistivity, in ohm-cm (ohm-m × 100)L = half the length, in cm (the wire length is 2L cm)a = wire radius, in cms = twice the depth, in cm (the depth is s/2)

R = In ...– 1+ρ4πL

ρ4πs

4La

+L2

3s22L4

5s41 –

Equation 7.4

where: R = resistance, in ohmsρ = soil resistivity, in ohm-cm (ohm-m × 100)L = length of the rod, in cma = radius of rod, in cm

R = In – 1ρ2πL

4La


1. Cathodic protection is now a necessity, nolonger an option, because of the broad shiftto underground construction and the use ofnonconducting materials underground.

2. Without cathodic protection, serious propertydamage and electric shock hazards may occur.

3. Buried copper as well as steel is vulnerableto corrosion.

4. Soil resistivities must be known. Without soilresistivity data, efforts to control corrosion arelikely to fail. Soil resistivities must be mea-sured as part of the preconstruction survey.

5. The electric neutral and grounding systemmust be treated as a dc circuit; design by“rules of thumb” and assumptions must beavoided.

6. The steps for cathodic protection in electricgrounding differ from the practices now

widely used because of differences betweenunderground pipelines, from which thepractices evolved, and electrical groundingsystems.

7. Anodes must be placed at the lowest soil re-sistivity locations available. Otherwise, manymay be ineffective.

8. Rectifiers must be used with great care untilexperience has been gained.

9. Follow-up measurements to monitor the ef-fectiveness of the cathodic protection shouldbe planned.

10. A schedule must be established for monitor-ing cathodic protection.

11. Follow-up measurements should be madeafter construction to monitor performance ofthe cathodic protection.


Direct-Bur ied System Design – 299

Direct-Buried System Design8

TrenchConstructionConsiderations

In This Section:

Most cooperatives find that direct-buried electricaldistribution systems are the most cost-effectivemethod to use for serving residential, commercial,and some industrial consumers. Material costsare generally less expensive—and labor costsare far less—than for conduit systems, in mostcases. However, the benefits of a direct-buriedsystem can be realized only if the cooperative’sengineer uses sound judgment in the following:

• Route selection,• Coordination with other utilities,• Trench construction details,• Designs based on method of installation (e.g.,trenching, plowing, directional boring),

• Roadway/railway standards, and• Terrain considerations.

Many of these factors are standard andgeneric for all parts of the country, and the2007 National Electrical Safety Code (NESC)(ANSI/IEEE C2) mandates many specific re-quirements that are to be followed without ex-ception. However, a good working knowledgeof local considerations is also a necessary fac-tor. Soil conditions, climate, other utility prac-tices, U.S. Department of Transportation issues,local railway system policies, and so on mustbe thoroughly understood and applied. Overtime, working relations with local developersand building contractors come into play in es-tablishing methods to use (or not use) in de-signing direct-buried systems.

Trench Construction Considerations

Trench Design Components

Trench Layout/Routing Considerations

Depth of Burial

Joint-Occupancy Trenches


RUS Bulletin 1728F-D806 (U.G. DistributionSpecifications) and the 2007 NESC describe thebasic standards of trench construction, princi-pally in terms of depth, width, and cable separa-tions. (Later in this chapter, burial depths aredescribed in detail.) However, many other fac-tors affecting trench design must supplement thenational standards to truly accomplish an effec-tive design. First of all, direct-buried systems

represent a style of construction that is minimallyprotected from dig-ins by other utilities or otheroutside agents. The following questions shouldbe asked when making the decision to use di-rect-buried systems:

• Is there a true likelihood of dig-ins fromother utilities (or others) in the location ofthe project?

300 – Sect ion 8

• Will the installation of trench warning tape(s)protect cables and effectively avoid dig-ins?

• Is additional protection—such as conduit,added depth, concrete barrier, or concrete-encased duct bank—needed?

• Are animals (rodents) an issue?• Are soil conditions (rock) an issue?• Is future cable maintenance an issue, consid-ering landscaping or other surface treatments?

Second, what construction equipment is avail-able for installation that may alter the design ofthe trench construction? The most common trenchinstallation is done with conventional chain-typetrenchers that provide a trench six to eight incheswide. Knowing the answers to the following ques-tions is critical in specifying proper trench units:

• Is the available equipment appropriate to pro-vide for effective tamping/soilcompaction/installation of trench warningtape given local soil conditions?

• What backfilling methods are available forsuch a narrow excavation?

If rocky soil is a consistent issue, the use of abackhoe (12 to 18 inches wide) might be moreappropriate to ensure good physical examinationof the trench floor for possible installation of cleansoil/sand bedding below and above the cable(s).Backhoe trenches allow better access for properbackfilling and compaction if soil conditions orsurface treatment requirements are a concern.An alternative form of trenching is the plow,

which is a major labor-saving device. There aretwo types of commonly used plowing methods:the static plow and the vibratory plow (discussed

8in detail in Book II). However, the economic useof plowing needs to be determined on the basisof the following, which may affect trench design:

• Are cables to be installed at multiple depths(e.g., primary at 42 to 48 inches/secondary at30 to 36 inches)?

• Are flexible (HDPE) conduits to be plowed in,with or without cables?

• Are sufficient amounts of cables required forinstallation to justify the cost of plowingequipment/operation?

• Are terrain/accessibility/soil types at the jobsite appropriate for the size of plow required?

• Are other utilities planning joint-useparticipation?

• Is the distance between transformers,pedestals, and switching cabinets such thatproductivity can be realized?

• Will different cable configurations be usedsequentially?

• Are there other existing utilities or other sub-surface features that must be crossed orparalleled?

Another alternative form of direct-buried trench-ing is the directional boring method, which againshould be justified regarding the following:

• Additional cost of installation (for reasons ofexisting landscaping, pavement, etc.),

• Soil conditions,• Warning tape that cannot be installed,• Depth of burial,• Ampacity requirements of cables,• Multiple cables at varying depths, and• Quantity of cables to be installed.

Trench DesignComponents

In addition to the basic requirements called out byRUS specifications and the NESC, the cooperative’sengineer needs to evaluate several other designconsiderations as a part of a successful installa-tion. The following is a list of both material andlabor factors that play into a successful design.

TRENCH WARNING TAPEMany cooperatives install trench warning tape toassist in preventing dig-ins. Typically, tapes are

installed 12 inches below final grade during thebackfilling/compaction process. If the top sur-face is paved (asphalt or concrete), it is recom-mended the tape depth be lowered to 18 inchesto avoid disruption by maintenance/replacementof the paved surface treatment. Trench warningtape is typically 6 inches wide, and can be sup-plied foil-backed for trench-locating purposes.Consistent with industry standards for utility lo-cation services, warning tape for electric systems


is usually red with “DANGER—ELECTRIC LINESBURIED BELOW” wording. Though not requiredby the NESC, trench warning tape can be an ef-fective tool in preventing dig-ins. Some states re-quire the use of warning tapes as a part of theirutility-locating programs.

BACKFILL/COMPACTIONThe cooperative engineer should be knowledge-able about local soil conditions and should un-derstand what is required for successfulbackfill/compaction of native soils. Sandy orloamy coastal soils compact differently than dostiff clays. Locations with rocky conditions re-quire additional care to ensure clean backfillabove and below cable systems to avoid jacketor insulation punctures or other cable damage.The cooperative engineer should also be aware

of the site specifics regarding whether the cablesare to be trenched on consumers’ premises or onroadway rights-of-way. Many state departmentsof transportation specify minimum compactionstandards, typically 90 to 95 percent Proctordensity levels. It is not merely a rating of restoringthe disturbed earth to assume settling no morethan 10 percent to five percent, respectively.

8Proctor density standards are based on the maxi-mum compactibility of a given soil in laboratoryconditions. A standard of 90 percent to 95 per-cent density is typically very difficult to achieveand definitely requires mechanical tamping.As a general rule, undisturbed soils naturally

occur at 80 percent to 85 percent Proctor den-sity, to put all this into perspective. If the partic-ular project requires a certain level of advancedcompaction, 90 percent to 95 percent Proctordensity should be specified, and reference shouldbe made to American Association of State High-way and Transportation Officials Designation T-99and ASTM Designation D-698. Compaction test-ing is relatively simple to perform and manylocal testing companies provide these services atnominal cost.

CABLE COMPACTION BEDSIn most trench backfill/compaction specifications,it is typical to call for a minimum bedding of cleanbackfill four inches below and above the direct-buried cables to prevent insulation or jacketpuncture from rocks (the 2007 NESC specifiesfour inches of tamped backfill in rocky soils, Sec-tion 352A). The NESC further specifies no ma-chine compacting within six inches of the cable.If finding clean backfill (or screening rocky or

unsuitable backfill) is not cost-effective, manyutilities elect to import sand for this purpose. Itshould be remembered, however, that the ther-mal conductivity of sand is often much lowerthan typical native soils. This lower thermal con-ductivity can de-rate cable ampacities and shouldbe examined closely on substation circuit exits,bulk feeder cables, or cables expected to beloaded heavily.

RISER POLE DESIGNThe riser pole is one part of the undergroundsystem that must be carefully considered duringthe design process. Not only is the riser oftenthe limiting factor for cable circuit ampacity, butthe physical arrangement of the cable circuit mustalso be carefully considered. Cable U-guards mustbe used with caution. Gaps between the polesurface and the guard can pose an opportunity forpublic access to unprotected cable surfaces. Con-duit risers generally provide a more satisfactory

FIGURE 8.1: Typical Trench Warning Tape. Source: ElectromarkIndustries, 2004.

302 – Sect ion 8

installation in most cases, even if vents have tobe installed to obtain adequate circuit ampacity.Conduits (or U-guards) near traffic ways

should be placed in a position with minimumexposure to traffic. Adequate cable support mustbe provided at the top of the conduit and sup-ported bends should be installed at the bottom.Conduit supports must be of a design that willprevent unaided climbing by the public. Manyother aspects of riser design are covered else-where in this publication. Also see Section 36 ofthe National Electrical Safety Code.

CONCRETE PROTECTION BARRIERSOn certain critical bulk feeder installations, or forhigh-voltage cable installations, considerationshould be given to pouring a three- to four-inchthick (nonreinforced) layer of concrete 12 to 18inches below grade to act as a protective barrierfrom dig-ins. Typically, these barriers should beused selectively and only for specific instancesin which circuit continuity is critical. Concretemix should not exceed 2,000 to 2,500 psi be-cause it should provide enough protection to

8

FIGURE 8.2: Cable Route Marker.Electro-Mark “DoMark” Style Mfg., 2005.

avoid a dig-in, but it also must be recognizedthat the barrier might have to be removed forcable repairs.Some utilities use flowable-fill, a light-duty

concrete mix that uses fly ash rather than gravelas its aggregate and sets up at around 400 to 500psi breaking strength. This 400 to 500 psi ratingappears equivalent to concrete when exposed,but can be removed easily with a standard back-hoe bucket. Most ready-mixed concrete plantsoffer flowable-fill at 75 to 80 percent of the costof normal concrete mixes. Most state depart-ments of transportation approve this mix onrights-of-way.Consideration should be given to requesting

that the ready-mixed concrete (or flowable-fillmixes) be tinted with red dye for added recogni-tion as an electric cable barrier. Trench warningtape added above the dye-tinted concrete mayalso reduce the probability of dig-ins.

TRENCH MARKERSOn underground substation circuit exits, un-

derground bulk feeder lines, or undergroundtransmission lines, the engineer should considerthe installation of cable route markers to denotecritical cable routes. The most effective routemarker is a plastic pedestal-type marker that ex-tends 24 to 36 inches out of the trench and gen-erally lists contact information, along with thecolor red and “DANGER—ELECTRIC LINESBURIED BELOW” wording.Route markers typically are specified to be in-

stalled every 100 to 200 feet, at road intersec-tions, other utility crossings, and angles orchanges in direction, recognizing terrain andlikelihood of damage/vandalism in light of theuse of the land traversed. In rural areas, thenormal spacings of these markers over straight-line trench routes can be lengthened to every1/8 to 1/4 mile. Neither the 2007 NESC nor RUSrequire cable route markers, as the philosophyof the use of these devices is a combination ofthe following:

• Marking the route for cable protection/dig-inavoidance, and

• Being a good “utility neighbor” by notifyingother utilities of a critical system.


The consuming public tends to regard cableroute markers as an eyesore, which can lead tovandalism. Without mandates by industry stan-

dards or regulations, cooperatives find mainte-nance of route markers ongoing.

8

Trench Layout/RoutingConsiderations

The successful layout/design of an undergroundelectrical distribution system depends, to a largedegree, on the effectiveness and workability ofthe routing selected for the site conditions. Rout-ing should be selected from point to point in thestraightest path to provide a logical geographicallayout, both for initial construction ease and forfuture troubleshooting, repairs, and cable loca-tion efforts. The 2007 NESC specifies this in351.A.2, and implies cables should be located sothey will be subjected to minimal future distur-bance. Bends and turns should respect equip-ment capabilities, and, more important, respectminimum cable bending radii.Cable routes should be selected to avoid nat-

ural detriments such as swamps, steep slopes,streams, bad or corrosive soils, mud, or unstablesoils that could shift, causing cable damage(2007 NESC 320.A.2). Following are considera-tions about other physical entities along thetrench route.

1. Cable routes along roadways (longitudinally)should be in the shoulder area far enoughaway to avoid undermining the road surfaceand to avoid disturbance from road surfacemaintenance. (Many state departments oftransportation provide minimum separationsand added burial depths.)

2. Bridges require additional separation, bothfor cable protection and to ensure trenchingoperations do not undermine bridge supports.

3. Railway systems require special attention, asthe 2007 NESC calls for 50-inch minimumburial depth below the top of the rails (36-inch depth if the rail system is a trolley carline), as per NESC 320.A.5.a. Many railwaysystems require additional burial depths forcrossings and have many restrictions for lon-gitudinal routes. Most railway companiesmandate steel conduit or casings for electriccircuit installations—rather than bare, direct-buried cables—often over the entire expanse

of the railroad right-of-way. Cables may bepermitted parallel to tracks on their rights-of-way, but pedestals, junction boxes, or man-holes generally are not allowed.

4. Direct-buried cables should be not closer toin-ground swimming pools (or auxiliary poolequipment) than five feet, as per NESC351.C.1. If this separation is not possible,conduit must be added.

5. Other utilities should be recognized whenroutes are selected to avoid crossing con-flicts and to provide each utility with theability to maintain its lines in the future.Typically, 12 inches is the established mini-mum separation between electric lines andother utilities, including telephone, CATV,water, sewer, gas, and steam lines. However,each utility can require additional separationby mutual agreements. Many telephone andCATV utilities require greater separation dis-tances of five to 15 feet to provide for main-tenance of lines. Steam lines requireadditional separation to avoid problems withheat dissipation, which reduces cable am-pacities. Cables closer to steam lines than 18to 24 inches will require thermal insulationmaterial between the two systems. A utilitycrossing or installation close by needs to re-flect the need to not undermine either utilitywith the initial trench installation or in futuremaintenance excavations.

6. Cables should not extend under buildingsbut, if required, must have mechanical pro-tection (conduit) and should be done in amanner that avoids foundation settlementand does not damage cable systems (NESC351.C.2.).

7. Cables should be installed below the sea-sonal frost line in an area, if possible, toavoid mechanical shear on cables resultingfrom freezing and thawing creating contrac-tion and expansion forces on cables.

Some existing soil conditions, such as solid orlayered rock, prevent cable burial at the requireddepth. The 2007 NESC 352.D.2.b allows lesser

burial depths if supplementalprotection is provided. Thissupplemental protection mustprotect the cable from damageresulting from normal activityat the earth surface. Conduit,or concrete-encased conduit,is the typical method of sup-plemental cable protection.

CLEARANCE FROM OTHER UTILITIESAnother requirement for direct-buried power ca-bles is separation from other buried utilities, in-cluding the following:

• Sewers,• Fuel lines,• Natural gas lines,• Water lines,• Telephone lines, and• CATV lines.

The 2007 NESC requires a minimum radialseparation of 12 inches from other utilities. Oc-casionally, terrain or available easements preventa 12-inch radial separation. For these instances,the cooperative and a telephone or cable utilitymay agree to use random separation. NESC Sec-tion 354 contains extensive special requirementsfor both electric and communication utilitiesusing random separation. However, separationfrom other utilities must not be less than 12inches. (See NESC Sections 353 and 354.)These minimum separations should provide

enough space for either utility to work on its un-derground lines without damaging the other util-ity’s lines. If this is not possible with a 12-inchseparation, then a greater separation is neces-sary. The NESC also recommends 12 inches ofvertical separation at crossings of different un-derground facilities. The cooperative and theother utility can agree to a lesser separation ifthe following apply:

• There is no harmful interaction betweensystems, and

304 – Sect ion 8

The NESC specifies the minimum earth cover re-quired over direct-buried power cables. Thisminimum cover is the distance from the top ofthe cable to the earth surface.Table 8.1 shows the 2007NESC requirements.To achieve the minimum

cover, make the trench depththree to four inches greater.The deeper trench depth al-lows for a three- to four-inchsoil bedding under the cableand for the cable diameter. Figure 8.3 illustratesminimum allowable burial depths for various ca-bles.The cooperative’s engineer should typically

specify burial depths in excess of the NESC min-imums. Typical trench depths are 30 to 36inches for secondary cable and 36 to 42 inchesfor primary systems. These depths allow somemargin for installation error and minor surfacechanges after completion. It must be recognizedthat the cooperative should make special al-lowances for areas where the surface may belowered later.For example, in rural areas, particularly in

areas subject to cultivation, consideration shouldbe given to using burial depths of 42 to 48inches for primary cables, and 36 to 42 inchesfor secondary cables, to accommodate all typesof farm machinery. This added depth helps tominimize dig-ins and future shallow cable issuesresulting from change in grade as a result offarming practices. It also provides more roomfor future cable installations, particularly in areaswhere rights-of-way are narrow or congestedwith multiple utilities.

8Depth of Burial

Burial depths

should exceed the

NESC minimums.

Operating Voltage Minimum Cover

0–150 volts phase-to-ground (streetlight cable ONLY)* 18 in.

0–600 volts phase-to-phase 24 in.

601–50,000 volts phase-to-phase 30 in.

50,001 volts and over phase-to-phase 42 in.

* Area or streetlight cables only if conflicts with other underground facilities exist

TABLE 8.1: Minimum Cover Requirements. Adapted from the 2007NESC, Table 352-1.


8

UR2 (D × W)Trenching UnitOne Cable or

Cable Assembly

NOTES:

1. Depth (D) and width (W) are specified in description of units.2. Depths specified are to finished grade.3. Over-excavate trenches as necessary to allow for (a) sand bedding or (b)

loose sandy soils or (c) where more than one cable will be installed in trenchand laying first cable may cause trench damage and reduction in depth.

4. Sand bedding is not part of these units and will be specified as needed.5. Backfilling is part of all trenching units, including joint-use trenches.6. Optional warning tape is recommended to be placed above the installed cable.

UR2–1 (D × W)Trenching Unit

Multiple Power CablesPrimary, Secondary, or Service

W W

DD

4”4”

2”

D

4”

2”

2”

UR2–2 (D × W)Trenching Unit

Power and Telephone Cable

TRENCHES FOR DIRECT

BURIAL CABLES

2000UR2TO

UR2–2

W

LEGEND

Sand or Clean Soil

Compacted Backfill Unless Otherwise Specified

Undisturbed Earth

12”Minimum

FIGURE 8.3: Burial Depth Requirements. Adapted from RUS Bulletin 1728F-806.

P T

306 – Sect ion 8

• Each utility can access its facilities withoutdamaging the other’s facilities.

Steam lines with only the required 12-inchseparation can lead to thermal damage of theunderground power cable. Steam lines createhigh ambient earth temperatures that signifi-cantly decrease the ampacity rating of the cable.To avoid these problems, the cooperative engi-neer must route power cable outside the effec-tive thermal range of a steam line. If adequateseparation is not feasible, a thermal barrier mustbe placed between the facilities.

OTHER CONSIDERATIONSAnother aspect to consider when choosing aburial depth is grade change. The 2007 NESC352.D.2.c requires the minimum cover require-ment to be met at the time of installation and atall times afterward. The best way to meet thisrequirement is to wait until final grade before in-stalling any cable. The cooperative engineermust also anticipate grade changes that occur af-ter final grade. For example, adeveloper will state that thesubdivision is at final gradebefore individual drivewaysare constructed. If the cable isplaced along the front prop-erty lines, then it needs to beburied deeper in anticipationof an earth cut for drivewayand sidewalk construction. Ifthe cooperative accommodates the developer byinstalling facilities before final grade is estab-lished, the cooperative incurs a substantial addi-tional burden during construction and becomesdependent on the developer to make final ad-justments to match plans.The forces of nature are also factors in deter-

mining proper burial depth. In some areas, thefrost level reaches the cable burial depth. Theearth movement caused by frost formation canmove the buried cable and nearby objects. Inthese areas, very close attention should be givento clean bedding material near the cable duringbackfilling. This, along with firm tamping, willminimize the opportunity for the freeze-thawcycle to move the cable against stones. Other

natural hazards are areas subject to erosion.Preferably, the cooperative engineer avoidsthese areas during the project layout phase.However, if cable must be installed in theseareas, then the burial depth must be increased.If the area has moderate to severe erosion, thecooperative engineer may consider supplemen-tal protection, such as installation in Schedule 40PVC conduit or encasement in concrete.The potential forces of man are also a factor

to consider in the layout of the system. This isparticularly true if the cable circuit is being in-stalled in the proximity of existing or futurewater, sewer, or gas lines. Other utilities havethe potential to not only cause substantial dis-ruption to electric service when they fail, but re-pair of the other utilities will often requireexcavation under emergency conditions. This in-creases the chances for accidental dig-ins wherethere is reduced separation.Another consideration for placing cable

deeper is protection from random dig-ins. If thearea is congested with other underground utili-

ties, then the chances of cabledamage by these other utilitiesincrease. These chances in-crease even more when thepower cable is installed beforeother utilities. This is particu-larly true with secondary ca-bles, because their requiredburial depth is only 30 to 36inches. An industry survey re-

ports that dig-ins are the major cause of faultson the underground secondary system. Increas-ing the depth of burial, especially on secondarycable, can help reduce dig-ins.A final consideration is clearance from under-

ground structures. According to the 2007 NESC351.C.2, underground power cable should notbe installed directly under building or storagetank foundations. If a cable must be placed be-neath a structure, the structure must have ade-quate support to prevent a harmful load transferto the cable.All these requirements mean that the design

engineer must be thoroughly familiar with siteconditions and intended uses before establishinga cable route and choosing an appropriate burial

8

Dig-ins are the

major cause of faults

on the underground

secondary system.


depth. Information on the route and depth mustbe communicated clearly to construction person-nel. Any route changes required by field condi-tions must be clearly recorded by constructionpersonnel so this information can be included in

permanent project maps. Failure of the design-construction team to follow a proper route at aproper depth will likely increase the number ofconsumer outages and require future relocationof the underground lines.

8

Joint-OccupancyTrenches

The NESC recognizes two types of joint trench:deliberate separation and ran-dom separation. A deliberate-separation joint trench re-quires a minimum of 12 inchesof separation between the dif-ferent utilities. This separationcan be horizontal or verticaland is illustrated in Figure 8.4.Maintaining the 12-inch sepa-ration allows electric utilitiesto share a trench with the fol-lowing utilities:

• Telephone,• CATV,• Gas (not generallyrecommended),

• Water, and• Sewer (not generallyrecommended).

Trench sharing with stormor sanitary sewers is generallynot practical because of thesize disparity in the facilities. In addition, sewerlines are often excavated for replacement or toclear obstructions. In these cases, the cables will

interfere with access and be more susceptible toaccidental damage by otherutility crews.The NESC defines randomseparation as any commontrench arrangement in whichthe cables have fewer than 12inches of radial separation.This type of joint trench is re-strictive; only certain utilitiescan place their facilities withrandom separation. The NESC

allows random separation of different electricpower cables. For example, the cooperative can

place primary and secondaryvoltage cables in the sametrench at the same depth withno horizontal separation. TheNESC also allows the randomseparation of some power andcommunication cables if cer-tain requirements are met.Table 8.2 summarizes thetypes of power cables that canbe in random separation with

telephone and cable television cables. The tablealso lists the requirements that the cooperative isresponsible for according to the 2007 NESC.

Deliberate-separation

joint trenches require

a minimum separation

of 12 inches.

Only certain utilities

can share random-

separation joint

trenches.

308 – Sect ion 8

8

UR2–3 (D × W)Service or Secondary

andTelephone

NOTES:

1. Depth (D) and width (W) are specified in description of units.2. Depths specified are to finished grade.3. Over-excavate trenches as necessary to allow for (a) sand bedding or

(b) loose and sandy soils or (c) where more than one cable will be installedin trench and laying first cable may cause trench damage and reductionin depth.

4. Sand bedding is not part of these units and will be specified as needed.5. Backfilling is part of all trenching units, including joint-use trenches.

UR2–4 (D × W)Primaryand

Secondary or Telephone

W

W

D

D

4”

4”

2”

D4”

12”

2”

2”

TRENCHES FOR DIRECT

BURIAL CABLES

2000UR2–3TO

UR2–5

W

12”Minimum

FIGURE 8.4: Joint Trench Use. Adapted from RUS Bulletin 1728F-806.

S T

T

TSP

S

P

LEGEND

Bedding Sand or Clean Soil

Compacted Backfill Unless Otherwise Specified

Undisturbed Earth

UR2–5 (D × W)Primary, Secondary,

andTelephone

12”Minimum

12”Minimum


1. Typical trench depths are 30 to 36 inches forsecondary cable and 42 to 48 inches for pri-mary cable (36 and 48 inches should bestrongly considered in many rural areas).

2. The most common method for installing cableis trenching in suburban areas and plowingin rural areas. Selecting the appropriateequipment depends on soil type, trenchingdepth, terrain, and trenching distance.

3. For trenches in rocky soils, cable should beplaced on a four-inch (minimum) bedding ofselect backfill, then covered with four inchesof select backfill. Covering should continuewith native clean backfill and compaction.Compaction should be made to 95 percentProctor density where settlement control isimportant. Avoid mechanical compactionwithin six inches of a cable.

4. Cable plowing does not open a trench andeliminates the need to backfill. Pull plowingis suitable for installing flexible conduit orcable in conduit. Chute plowing should beused to install cable without conduit.

5. Some locations, such as existing subdivisionswhere cable replacement is considered, mayrequire directional boring or horizontal di-rectional drilling.

6. There are two types of joint trench. Deliber-ate-separation joint trench requires a mini-mum separation of 12 inches. Random-separation joint trench is very restrictive.

7. Conduit should be used wherever additionalcable protection is required or where thedeferral of future excavation costs will justifythe additional initial expense.

8Type of Power Cable Operating Voltage Requirements

600-V 240/120 V, 1Ø NoneInsulated Cable 240 V, 3Ø delta

208/120 V, 3Ø grounded-wye [NOTE: 480-V or 600-V, 3Ø, delta systems cannot be in random-lay480/277 V, 3Ø grounded-wye with communication cables.]

15-, 25-, or 35- kV 4,160/2,400 V, 1Ø or 3Ø • Ground conductor must be in continuous contact with earth. ShortBare Concentric Neutral Cable or 12,470/7,200 V, 1Ø or 3Ø sections of conduit for crossing under roads are allowed if neutralSemiconducting Jacketed Cable 24,940/14,400 V, 1Ø or 3Ø is continuous in conduit. Long sections of conduit require installation

34,500/19,900 V, 1Ø or 3Ø of a separate ground conductor that is in contact with the earth andclose to the cable.

• Ground conductor must be adequate to withstand availablefault conditions.

• When faulted, the cable will be promptly de-energized.• Ground conductor and communication cable shield or sheath must

be bonded at 1,000-foot intervals (maximum spacing).• Concentric neutral must be corrosion-resistant material.• Semiconducting jacket must have a radial resistivity of 100 ohm-m

or less.

15-, 25-, or 35- kV 4,160/2,400 V, 1Ø or 3Ø • Copper concentric conductor must be effectively grounded.Jacketed Concentric Neutral Cable 12,470/7,200 V, 1Ø or 3Ø • Minimum conductance of concentric neutral must equal one-half• Direct Buried or 24,940/14,400 V, 1Ø or 3Ø conductance of phase conductor.• Installation in Nonmetallic Conduit 34,500/19,900 V, 1Ø or 3Ø • Ground conductor must be adequate to withstand available

fault conditions.• Minimum of eight ground rods per mile, not including grounds at

individual services.• Prompt de-energization of a faulted conductor.• Ground conductor and communication cable shield or sheath must

be bonded at 1,000-foot intervals (maximum spacing).

TABLE 8.2: Requirements for Random-Lay Joint Trench. Adapted from 2007 NESC Section 354.


Conduit System Design – 311

Conduit System Design9Conduit SystemDesign

In This Section:

In some situations, conduit systems may offermany substantial advantages to electric utilities.Although conduit-enclosed cable installationshave a higher initial cost, the lifetime advantagesmay make them the preferable installation in avariety of circumstances. Major advantages ofconduit installation include the following:

• Improved cable protection from dig-ins,• Ability to add cables along the route without

additional excavation,• Ability to replace cable without excavation,

and• Better use of utility easement for multiple

circuits.

The disadvantages when compared with di-rect burial are the following:

• Higher initial cost, and• Lower ampacity for a given cable size.

CONDUIT SYSTEM TYPESDistribution system conduit installations gener-ally fall into one of three categories:

1. Direct buried,2. Concrete encased, and3. Concrete encased with manholes (or

splice boxes).

Direct-buried conduit is simply installed in atrench and conventional backfill techniques areused. This approach generally requires astronger conduit (Schedule 40 or better), but ithas the lowest initial cost of all conduit systems.Typical direct-buried conduit installations arestreet crossings, single-circuit runs, and exits forsmall substations. Direct-buried conduit is partic-ularly suitable where only minimal mechanicalprotection is needed and low cost is important.

The next level in the hierarchy of conduit sys-tems is a concrete-encased duct bank. This isgenerally used where multiple circuits are in-stalled, or will be installed, along a route. En-cased conduit is also advisable where additionalmechanical protection from dig-ins is needed.As with direct-buried conduits, the length ofruns is limited by cable-pulling criteria. How-ever, in loose soils, the encased conduit will bemore stable under high cable-pulling tensions.In fact, encased conduit is advised for longerruns, particularly if bends are involved.

Where conduit runs are longer than allowablecable-pulling lengths, or where access for lateralsor taps is needed, manholes and/or splice boxesmust be installed for access and splicing. Theseallow intermediate pull points that will lead tolower cable-pulling tensions. Manholes and/orsplice boxes can also be strategically located toeliminate bends or sharp angles in conduit runs.

Conduit System Design and Installation

Cable Pulling


312 – Sect ion 9

Judicious location of manholes will also lowerpulling tensions and yield a more convenient in-stallation. Longer duct runs may also need to betapped for intermediate service locations. Wheresuch service points are either a present or a fu-ture requirement, a manhole installation willsimplify access to the cable circuits and producea more flexible system.

Typically, manholes are full-size, below-gradeenclosures that allow personnel to enter andwork within, standing erect, usually with six toeight feet of head room. Splice boxes are usu-ally surface mounted, not intended for person-nel entrance, and usually only three to five feetdeep. Much smaller in size, splice boxes areworked from the surface andgenerally involve only one totwo feeders.

In summary, conduit sys-tems are recommended wher-ever additional cableprotection is required or thedeferral of future excavationcosts will justify the additionalinitial expense. Manhole/ductbank systems are particularlyadvantageous where long,continuous runs of multiplecircuit underground are expected over the life ofthe project.

CONDUIT TYPESOver the years, the electric utility industry hasused a wide variety of conduit types. Today, themain conduits used on UD systems are steel andplastic (predominantly PVC and HDPE). Each ofthese materials is offered in several configurations.

The steel conduit that utilities use almost ex-clusively is galvanized Schedule 40. This type ismostly used where extra mechanical protectionis needed. Examples are riser poles or some di-rect-buried conduit applications. Although steelconduit generally provides better protectionthan does a similar-size PVC conduit during adig-in, steel does have its disadvantages. It isharder to bend, susceptible to corrosion, andoften more expensive. Furthermore, galvanizedsteel conduit is magnetic. This means that heavyunbalanced currents (such as a single-phase

9conductor in its own steel conduit, without aneutral return) passing through a steel conduitwill produce heat as a result of eddy currents inthe conduit. When this condition is encountered,nonmagnetic conduits must be used.

Metallic conduit other than galvanized Sched-ule 40 (or Schedule 80) should never be used ona utility system. Types not recommended includeelectrical metallic tubing (EMT) and intermediatemetal conduit. Such conduits are lighter inweight, have less secure couplings, and areoften more susceptible to corrosion. The onlygeneral exception is Schedule 40 aluminum con-duit, which might be used in some locationswhere atmospheric corrosion is a concern and

earth contact can be avoided.Where corrosive conditionsexist, Type 304L or Type 316stainless steel conduits mightbe considered.

Plastic conduits are nowavailable to utilities in a widevariety of sizes and materials.The predominant material isPVC and will be used in allexamples. Other nonmetallicmaterials include acrylonitrile-butadiene-styrene (ABS) plas-

tic, HDPE, and fiberglass-reinforced epoxy (FRE).ABS conduit is similar to PVC, but it has higherwall thickness to compensate for a lower mater-ial strength. In addition, the solvent cementwelds on ABS and PVC are chemically different,so neither will give satisfactory results on theother conduit. Therefore, ABS and PVC shouldnever be mixed on a project. It is also advisablethat a cooperative not mix these conduit materi-als on its system as different solvent cements arerequired and defective joints will be produced ifthe products are accidentally interchanged.

HDPE conduit is much more flexible than PVCconduit and generally comes on reels, ratherthan precut straight lengths. HDPE conduit isparticularly useful in directional bored applica-tions, where the flexible nature of the conduit isan advantage. The conduit comes in smoothwall, ribbed wall, and corrugated wall, depend-ing on the application, and also comes in multi-ple colors and markings. Reels can be provided

Metallic conduit

other than galvanized

Schedule 40 (or

Schedule 80) should

not generally be used

on a utility system.


with continuous lengths up to 4,000 feet, (e.g.,two-inch inside diameter [I.D.]. The one caution,and possibly only drawback, to HDPE conduit isthat it tends to have a coiled “memory” and can-not be allowed to curve in the trench floor be-fore compaction. Eliminating these curves canbe very difficult when the coiled HDPE conduitis being installed in an open trench. If the con-duit is not installed in a controlled, straight line,the additional curved bends, while seemingly in-significant during conduit installation, greatlyamplify cable-pulling tensions.

FRE conduit is a specialty item generally usedin applications more typically associated withsteel conduit because FRE conduit can havehigher strength than even Schedule 80 PVC. Itcan also be installed with longer unsupportedspans without excessive long-term sag. FRE con-duit, like PVC, has high corrosion resistance.These characteristics make FRE conduit particu-larly attractive for duct lines suspended beneathbridges and for riser installations.

Throughout the history of electric utilities, avariety of other conduit mate-rials have been used. Theserange from early treated woodconduits to terra cotta tileducts. Some of the other mate-rials most commonly usedsince the 1950s include fiber,concrete, and asbestos ce-ment. Fiber duct, often knownby the trade name Orangeburg, was made ofmolded wood fiber impregnated with an as-phaltic compound. Fiber duct was used mainlyin concrete encasement but, even then, it wouldeventually absorb moisture and deteriorate. Con-crete duct was generally installed as a direct-buried conduit or multiple-tile duct. Thismaterial was naturally very heavy and did notgain wide acceptance with electric utilities.

Asbestos cement duct, otherwise known asTransite™, gained wide acceptance in concrete-encased conduit duct banks. It also saw use asa direct-buried conduit. Major advantages in-cluded a smooth interior surface and very highflame resistance. However, this material was ex-tremely hard and brittle. It was also extremelyinflexible. The combination of these characteristics

9required special skills and care during installa-tion. With the advent of economical PVC andconcerns about asbestos content, asbestos ce-ment conduit is no longer installed.

Plastic conduit is the most commonly usedelectrical duct material. Therefore, engineeringand construction personnel need a workingknowledge of the plastic conduit types com-monly used on electric systems.

Table 9.1 gives the specific classifications ofplastic conduit.

One important determination for a conduitapplication is whether it will be used strictly un-derground or if it may have above-ground instal-lations. As solar radiation affects most plastics,only those conduits classified for above-grounduse may be applied in sunlight. Classifications ofdirect burial (DB) and encased burial (EB) meanthat all above-ground exposure must beavoided. Conduit types classified “above ground”may be used in either location.

Table 9.2 shows the dimensions of these vari-ous conduit configurations. Table 9.3 compares

the relative strengths of theseconduit types in the four-inchnominal size. Table 9.4 liststhe impact strength of the vari-ous sizes of PVC conduit. Forsimilar information on FREconduit, refer to the specificFRE manufacturer.

Direct-Buried Conduit Design and InstallationThe most common type of conduit application isthe direct-buried system. Here, the conduit con-taining the electrical cable is placed into theground without additional encasement. Whenthe installation is made by trenching, the conduitis placed on a smooth trench bottom beforebackfill is placed. When the trench is being pre-pared, the bottom must be leveled to provideeven support to the conduit. Rock outcroppingsmust be cushioned with a layer of clean, com-pacted fill to avoid high-pressure points on theconduit when backfill is placed.

The initial backfill layer should be tamped onthe sides of the conduit to develop sidewall sup-port. This support is important to provide stabil-ity during the pulling process and to resist

Never use DB or

EB conduit

above ground.

314 – Sect ion 9

9Specification

Conduit Designation Material NEMA Other Description and Application

EB-20 PVC TC-6 ASTM F512, Encased burialUL651A

EB-35 PVC TC-8 ASTM F512 Encased burial, extra strength

DB-60 PVC TC-6 ASTM F512 Direct burial

DB-120 PVC TC-8 ASTM F512 Direct burial, extra strength

Schedule 40, Type II PE — — Normal duty, direct burial

Schedule 40, Type III PVC TC-2 UL 651 Normal duty, above ground

Schedule 80, Type IV PVC TC-2 UL 651 Heavy duty, above ground

HDPE, Smooth-Wall HDPE TC-7 ASTM D3035 Normal duty, direct burialASTM D2239ASTM D2160

HDPE, Ribbed HDPE TC-7 ASTM D3035 Normal duty, direct burialASTM D2239ASTM D2160

HDPE, Corrugated HDPE TC-7 ASTM D3035 Normal duty, direct burialASTM D2239ASTM D2160

TABLE 9.1: Classifications of Plastic Conduit.

Conduit Size Minimum TC-6 TC-8Inside Diameter EB-20 DB-60 EB-35 DB-120 Schedule 40 Schedule 80 HDPE-40

2” 0.060 0.060 0.060 0.077 0.154 0.218 0.154

3” 0.061 0.092 0.076 0.118 0.216 0.300 0.216

4” 0.082 0.121 0.100 0.154 0.237 0.337 0.237

5” 0.103 0.152 0.126 0.191 0.258 0.375 0.258

6” 0.125 0.182 0.152 0.227 0.280 0.432 0.280

TABLE 9.2: PVC Duct Dimensions—Minimum Wall Thickness.

TC-6 PVC TC-8 PVCCharacteristics EB-20 DB-60 EB-35 DB-120 Schedule 40 Schedule 80 HDPE-40

Collapse pressure, psi 6.7 17.0 9.2 36.6 108.7 326.5 96.0

Impact resistance, ft-lb. 25.0 60.0 40.0 80.0 220.0 310.0 N/A

Weight, lb./100 feet 92.0 127.0 109.0 158.0 234.0 310.0 136.2

Pipe stiffness, lb./in.* 20.0 60.0 35.0 120.0 461.2 117.8 N/A

* Specifically, pounds per inch deflection at five percent change in internal diameter

TABLE 9.3: Comparison of Characteristics for Four-Inch Diameter PVC Duct.


crushing when full vertical backfill pressure isapplied later. Crushing forces can also be re-duced by not tamping abovethe conduit until an adequatethickness of backfill has beenplaced. The thickness of back-fill required will depend onthe force applied by the tamp,the surface area of the tamp,and the soil characteristics.Type DB conduit is more sus-ceptible to crushing thanSchedule 40 (or 80) conduitbecause its wall is thinner. If rocky soils are usu-ally present or clean backfill cannot be ensured,Schedule 40 conduit should be used instead ofType DB for direct-buried installations. Failureto follow these guidelines will lead to conduitwith blockages or reduced inside dimensions. Inthese cases, the conduit will be unusable or maydamage cable during installation.

If multiple conduits for electric circuits arebeing installed in the same trench, a minimumof three inches of clearance must be providedbetween the conduits. This clearance not onlywill allow for proper backfill placement andtamping but also will improve heat dissipation.If the decision is made to use close spacing ofconduits for individual enclosure of large, high-capacity cables (this is not recommended), theseshould be Class DB-120 or Schedule 40 to with-stand the point pressures created by conduit-to-conduit contact.

Where conduit is installed by plowing, a coil-able polyethylene product will usually be used.Plowing of coilable polyethylene conduit may

be accomplished successfully in moderate tem-peratures with proper equipment. With conduit

sizes larger than two inches orduring cool weather, makesure the conduit installation isstraight and does not havebends caused by conduit“memory” as it is removedfrom the reel. Curves causedby this phenomenon can dras-tically increase cable-pullingtensions. This condition shouldalso be avoided if a coilable

conduit, with or without a cable, is being in-stalled by conventional trenching.

In some cases, short runs of straight, jointedconduit sections may be installed by the pull-inplow method. In these cases, it is extremely im-portant that all joints are properly made andcured before pulling begins; otherwise, thejoints can separate.

Concrete-Encased Duct Design and InstallationConcrete-encased duct banks are generally usedwhere multiple circuits are required along con-gested routes or where extra physical protectionfor cables is warranted. Installations of this typerequire careful site investigation and advanceplanning, particularly because of the size of theduct line and the need to keep it straight andproperly graded. Unexpected conflicts with un-derground obstructions can cause major problemsas a large multiple-conduit, concrete-encasedduct line is being installed.

This type of installation begins with an opentrench. The trench must be wide enough to

9Conduit Size Minimum TC-6 TC-8

Inside Diameter EB-20 DB-60 EB-35 DB-120 Schedule 40 Schedule 80

2” 20 20 20 25 190 300

3” 20 40 30 50 220 525

4” 25 60 40 80 220 525

5” 30 85 55 110 220 525

6” 40 120 75 150 220 525

TABLE 9.4: PVC Duct—Impact Strength (Foot-Pounds).

Curves in coilable

conduit can greatly

increase cable-pulling

tensions.

316 – Sect ion 9

Establishing a well-drained conduit system willfacilitate cable installation and removal as wellas improving the cable operating environment.

The trench bottom should be adequately com-pacted where conduit support spacers will be in-stalled. Loose material in the trench bottomshould be removed or compacted so the ductbank will have proper support at all points.

For electrical distribution duct lines, threeinches of concrete cover should be providedat both the top and bottom extremities of thebank. A minimum of two inches of horizontalconcrete cover should be provided between theoutside ducts and the trench wall. For properheat dissipation, three inches of clearanceshould be provided between conduits (seeFigure 9.1). A simple way to maintain thesedimensions both vertically and horizontally isby using conduit spacers.

Concrete installed around duct banks mustbe properly placed to fill all voids, provideoptimum heat transfer, and properly protectcables. Concrete that has small aggregate, gen-erally one-half-inch or less, which will readilyflow between ducts must be used. A concreteslump of seven to eight inches must also bespecified to allow reasonable flow. The slumpvalue is a measure of how much fluid is inthe concrete. A higher slump value means theconcrete contains more fluid and is “wetter.”A slump value higher than eight inches is notrecommended as the high fluid content willmake it more difficult to hold the conduits inplace during the pouring process.

Concrete strength should be specified in therange of 1,500 to 2,500 psi. Although standardready-mix concretes are often delivered withstrengths of 3,000 to 4,500 psi, there is no needfor the stronger and more expensive mix in un-reinforced duct bank encasements. The concretesupplier should be consulted beforehand in orderto get the proper concrete mix at the job site. Hecan then design an economical mix that will meetthe special needs of duct bank construction. It isalso vitally important that vibration be used dur-ing the pouring process. Vibration will facilitatethe flow of concrete and minimize voids.

During the actual pouring process, three im-portant requirements should always be verified:

9

FIGURE 9.1: Typical Duct Configurations.

3"Min.

3-WayConcrete-Encased

3-WayDirect-Buried




* Designates Circuit LocationUndesirable for Loaded Circuit

2" Min.

provide proper duct spacing and side clear-ances. However, the trench must not be madetoo wide, as the trench wall will generally beused as a form for the concrete encasement.Extra trench width will lead to the need for un-necessary concrete.

Trench design should also recognize the de-sirability of well-drained conduits. This requiressloping of the conduit to a point, such as a man-hole, where water can be removed from the sys-tem. Each section of conduit can be sloped in asingle direction or it can be drained toward eachend. While the overall slope of the trench is im-portant, the conduit must be graded so there areno local pockets that can accumulate water.


• Hold-down of the duct and spacers,• Control of the concrete flow, and• Prevention of duct collapse.

Precast concrete weights, often called “suit-cases,” should be applied to the top of the con-duit before pouring. These weights will keep theconduit from floating when it is surrounded withwet concrete. As noted above, the slump valueshould be fewer than eight inches to providefriction that will help keep conduits in place.The amount of weight required will dependon the following factors:

• Number of conduits,• Size of conduits,• Slump of concrete,• Use of vibration, and• Other anchoring methods used.

The amount of weight needed to keep conduitfrom floating is determined by the buoyancy ofthe empty conduits in wet concrete, given thatthe concrete has a unit weight of about 150 lb.per cubic foot. To counteract the maximum pos-sible buoyancy of a six-way, five-inch duct bank,a 150-lb.weight is needed on each foot of ductline while the concrete is being poured. This ex-ample shows how important it is to keep concreteslump as low as practicable and to use only asmuch vibration as needed to achieve good con-crete flow. As an alternative to the precast concretesuitcases, some manufacturers of duct spacershave provisions for driving hold-down rodsthrough the spacers to avoid conduit floating. Thismethod, coupled with nonmetallic bands or straps,can also be used to prevent conduit floating.Caution should be used with hold-down rods insoft soil and larger duct bank configurations.Softer soils offer lower pullout resistance, thusrequiring longer hold-down rods driven deeper.

When pouring concrete encasement, the dis-tance that the wet concrete falls into the trenchshould be minimized. If the ready-mix deliverytruck chute cannot be placed near the top of theducts, a hopper (funnel) and hose arrangementcan be attached to minimize the free-fall dis-tance. If the fall distance is too great, there willbe two adverse results:

1. The aggregate will tend to segregate out ofthe concrete mix, thereby producing porous(honeycomb) sections in the encasements,and

2. An excessive free-fall distance may disruptthe conduit configuration or break joints.

The use of a splash board will also helpdirect the concrete flow into the trench andshould be used to prevent concrete flow againstunsupported trench walls. Otherwise, loose dirtwill be embedded in the wet concrete, causingvoids. All the above conditions must be avoidedfor a satisfactory duct installation.

When large duct banks (above six-way) arebeing installed, the collapse pressure rating ofthe particular conduit should be computed withthe expected compressive force on the bottomconduit during pouring. To make this calculation,the depth of the lowest conduit in feet is multi-plied by 1.03 psi/ft of depth to find the com-pressive force (in psi) on the lowest conduit. Forinstance, if a three-layer duct bank has a layer offive-inch conduit with three inches of top coverand three inches between layers, the lowestconduit is about 25 inches (2.1 feet) deep. Thisproduces a compressive force of approximately2.2 psi. Table 9.5 shows that the compressivestrength of five-inch type EB-20 conduit is 5.9psi. Therefore, this application of EB-20 is satis-factory. If the compressive force had approachedthe conduit rating of 5.9 psi, a higher grade ofconduit such as EB-35 would be required. Crewsmust be instructed that conduits, particularly thethinner-wall Type EB varieties, should not bewalked on to avoid cracking, collapse, or defor-mation of the conduit.

GENERAL CONDUIT SYSTEM LAYOUTThe first problem in engineering an under-ground conduit system is determining the loadsto be served by the system, both now and in thefuture. Present and future requirements mustalso be determined for circuits traversing thedesign area to serve loads in other areas. Theserequirements, coupled with the characteristicsof the design area, will determine the type ofunderground system to be installed.

9

318 – Sect ion 9

For example, if the problem is substation exitcircuits in an open rural area with a wide areafor circuit exits and good soil conditions, the ob-vious answer may be direct-buried circuits. Thesehave lower initial cost and better thermal perfor-mance than either direct-buried conduit or con-crete-encased conduit systems. However, if onlya limited space is available for installing electriccircuits, construction conditions are difficult, orseveral circuit additions are expected over thelife of the facility, a conduit system is probablythe proper answer for lowest long-term costs.Of course, cable installation forces and damageprobability must also be considered whenchoosing the final conduit configuration.

Regardless of whether direct-buried conduitor encased conduit is chosen, the total systemmust be designed in light of present and futureloads and the circuits required to serve theseloads. Therefore, the first step is to define loadswithin the design area and determine the trans-former locations required to provide service. Thendistribution circuits will be designed to provideprimary voltage to all transformers, generallywith an open-loop configuration. If a transformerlocation will provide service through radial sec-ondary circuits, these secondary circuits must bedesigned. This situation is often encountered incongested areas such as shopping centers. Afterall circuits are designed for local service, anyunderground circuits that will pass through thedesign area should be considered. In the case ofsites near substations, the through-circuits maybe the only factor considered.

After the circuit design is complete, the con-duit system configuration should be designed to

accommodate the circuits in each location. Stan-dard conduit configurations as shown in Figure9.1 should be used to simplify construction.Duct bank configurations of greater than threeconduits are generally installed using concreteencasement. Encased duct will also be neededwhere cable-pulling tensions are high or bendsare in the conduit. Inner conduits should not beused for heavily loaded cable circuits as heatdissipation is much better for peripheral loca-tions. Section 4 discusses further the thermalperformance of cables in a conduit system.

If both primary and secondary circuits are lo-cated in the same duct run, it is generally prefer-able to plan on secondary circuits being locatedin the upper ducts, particularly if the secondariesare serving a load at an intermediate point inthe duct run. Turning of the upper ducts is sim-pler and allows the lower conduits to continuestraight with the main conduit run. Other con-siderations are the greater mechanical protectionafforded lower conduits and the simplified man-hole internal arrangement. See Figure 9.2.

Small features of duct bank design that areoften overlooked are provision for area lightingcircuits and future electric utility communicationcircuits. Both of these uses generally requiresmall conduits (two-inch minimum diameter isrecommended) and are easy to initially install.Street and area lighting conduits should be lo-cated in the upper corners of the duct bank (seeFigure 9.3). Lighting conduits should be loopedto facilitate multiple light locations to be servedby a single circuit.

Communication conduits are for the installa-tion of circuits owned and maintained by the

9Conduit Size Minimum TC-6 TC-8

Inside Diameter EB-20 DB-60 EB-35 DB-120 Schedule 40 Schedule 80

2" 11.2 11.2 11.2 26.6 117.1 595.8

3" 6.6 15.2 8.2 34.0 181.3 487.3

4" 6.7 17.0 9.2 36.6 108.7 326.5

5" 5.9 18.9 10.3 38.2 75.5 235.6

6" 6.1 19.6 11.2 38.0 57.0 212.5

TABLE 9.5: PVC Duct Collapse Pressure (PSI).


9

FIGURE 9.2: Typical Duct Line and Manhole Arrangement.

FIGURE 9.3: Typical Arrangements for System in Figure 9.2.

To Area Lighting

To Remote Loads

To Local Loads

To Area Lighting

ManholeManholeA

A

B

B

C

F F F F

D D

E E

D D

CPrimary & Secondary Ducts Primary Duct

Second

aryDu

ct

Second

aryDu

ct

TransformerLocation

4 65 4 5 6

1 2 3

Duct123456

Size5"5"5"2"5"2"

UsePrimary LoopSparePrimary LoopArea LightingSpareUtility Communications

Duct123456789

Size5"5"5"5"5"5"2"2"2"

UsePrimary LoopSparePrimary LoopSecondarySecondarySecondaryArea LightingUtility CommunicationsArea Lighting

Duct123456

Size5"5"5"2"2"2"

UsePrimary LoopSparePrimary LoopArea LightingUtility CommunicationsArea Lighting

Section A-A Section B-B Section C-C

Section D-D Section E-E Section F-FDuct123

Size5"5"5"

UseSecondarySecondarySecondary

Duct123456

Size5"5"5"5"5"5"

UsePrimary LoopSparePrimary LoopSecondarySecondarySecondary

Duct12

Size2"2"

UseArea LightingArea Lighting

1 2 3 1 2 3

4 5 6

1 2 3 1 2 3

7 8 9

4 5 6

1 2

cooperative only. Such circuits might be used foralarm, control, or metering associated with elec-tric distribution. Section 32 of the NESC has in-formation on the allowable location ofcommunication ducts and circuits. If other condi-tions allow, the preferred location of communi-cation circuits is the top center conduit. Makingprovisions for these circuits is recommended, es-pecially in areas where concrete-encased ductsare installed or high load density exists.

DETERMINATION OF CONDUIT SIZESFOR CABLE INSTALLATIONAn important step in analyzing the duct banksystem is to examine the size and number of ca-bles required and to select the appropriate con-duit size. For the analysis of conduit fill, theNational Electrical Code (NEC) is an excellentsource that has been tried and tested countlesstimes. Although the NEC does not legally bindcooperatives, it is still an excellent standard andapplication guide on conduit fill.

Tables 9.12 through 9.15 list the minimum sizeof conduit necessary to accommodate certainnumbers and sizes of underground power andsecondary cables. The tables are based on themaximum fill requirements of the NEC, whichare 53 percent maximum fill for one cable in aconduit, 31 percent maximum fill for two cablesin a conduit, and 40 percent maximum fill forthree or more cables in a conduit. The tradesizes, inside diameters, and maximum areas offill for various sizes of conduit are shown inTable 9.6.

The cables shown in Tables 9.7 through 9.11all have ICEA Class B concentric stranded con-ductors, unless an “S” indicating solid conductorappears beside the conductor AWG size. Thelisted cables have standard thickness of conduc-tor shield, insulation, insulation shield, andjacket, and standard numbers and size of con-centric neutral wires in accordance with ICEAspecifications. If other than standard specifica-tions are used for cable, or if other than strandedor solid conductor is used, the overall cross-sec-tional area of 15-, 25-, or 34.5-kV power cablecan be calculated with Equation 9.1. For 600-voltsecondary cable, the overall cross-sectional areacan be calculated with Equation 9.2.

320 – Sect ion 9

9Inside 1 Cable Area 2 Cables Area 3 Cables Area

Trade Size (in.) Diameter (in.) Area (sq. in.) x 53% (sq. in.) x 31% (sq. in.) x 40% (sq. in.)

2 2.067 3.36 1.78 1.04 1.34

2 1/2 2.469 4.79 2.54 1.48 1.92

3 3.068 7.39 3.92 2.29 2.96

3 1/2 3.548 9.89 5.24 3.06 3.95

4 4.026 12.73 6.75 3.95 5.09

5 5.047 20.01 10.60 6.20 8.00

6 6.065 28.89 15.31 8.96 11.56

TABLE 9.6: Conduit Fill.

Equation 9.1: Shielded Concentric Neutral Cable Diameters.

Diameter = C + 2CS + A + 2I + 0.030 + 2IS + 2N + 2J

where: C = Diameter of the conductorCS = Thickness of the conductor shield (see Table 9.7)A = Addition Factor:

• 0.010 inches for 25-kV and 34.5-kV cables withconductor larger than #4/0

• 0.000 inches for all other cable constructionsI = Insulation wall thicknessIS = Insulation shield thickness (See Table 9.8)N = Thickness of concentric neutral wiresJ = Thickness of outer jacket:

• 0.080 inches for conductors through 1.50 inchesover the concentric neutral

• 0.120 inches for conductors larger than1.50 inches over the concentric neutral

Conductor Size (AWG or MCM) Conductor Shield (in.)

#8–#4/0 0.012

25–550 0.016

551–1,000 0.020

1,001 and larger 0.024

TABLE 9.7: Conductor Shield Thickness.

Diameter Over Insulation* Insulation Shield (in.)

0–1.000 0.060

1.001–1.500 0.075

1.501–2.000 0.090

2.001 and greater 0.105

* Diameter over insulation = C + 2CS + A + 2I

TABLE 9.8: Insulation Shield Thickness.

Full Neutral 1/3 Neutral

ALUMINUM Conductor (AWG or MCM) Neutral Wire Size (AWG) Thickness (in.)

Through #1/0 Through 350 #14 0.0641

#2/0, #3/0 500–750 #12 0.0808

#4/0, 250 1,000 #10 0.1019

350 1,250–1,500 #9 0.1144

N/A Over 1,500 #8 0.1285

N/A = not applicable

TABLE 9.9: Concentric Neutral Thickness—Aluminum Cables.


CONDUIT/CABLE TABLESTables 9.12 through 9.15 have been developedon the basis of the aforementioned requirementsof the current 2002 NEC and Equations 9.1 and9.2 for determining the diameters of requiredconduits for typical primary and secondary con-ductors. The sizes of conduit recommended aresuggested based on an average of many manu-facturers of cables, reflecting the fact that actualdiameters of cables vary greatly.

Selection of the appropriate conduit size mustalso consider the following factors:

• Future cable capacity increases,• Pulling tension considerations,• Heating and ventilation (see Section 4),• Cost considerations, and• Standardization of conduit sizes.

9Full Neutral 1/3 Neutral

COPPER Conductor (AWG or MCM) Neutral Wire Size (AWG) Thickness (in.)

Through #2/0 Through 250 #14 0.0641

#1–1/0 350 #12 0.0808

2/0–3/0 500–650 #10 0.1019

4/0 750 # 9 0.1144

N/A 1,000–2,000 # 8 0.1285

TABLE 9.10: Concentric Neutral Thickness-Copper Cables.

Equation 9.2: Unshielded Cable Diameter.

Diameter = C + 2I

where: C = Diameter of the conductorI = Insulation wall thickness

Insulation Thickness (in.)

Conductor Size (AWG or MCM) Regular* Ruggedized*

#4–#2 0.060 0.075

#1–#4/0 0.080 0.100

225–500 0.095 0.130

600–1,000 0.110 0.145

* Regular insulation consists of one layer of low-density polyethylene. Ruggedized designconsists of two layers of equal thickness bonded together: an inner layer of low-densitypolyethylene and an outer layer of high-density polyethylene. Various manufacturers usedifferent combinations of layers and layer thickness to achieve ruggedized designs. Verifyactual diameters with actual cables being used.

TABLE 9.11: Secondary Cable Insulation Thickness.

322 – Sect ion 9

9Minimum Size of Conduit Necessary to Accommodate Primary Underground Power Cable:

15-kV Cable – 220-Mil Insulation Wall, Concentric Neutral Construction

Minimum Conduit Size (Inches) for Numbers of Primary Cables, Based on Neutral Construction

Conductor 1 Cable per Conduit 2 Cables per Conduit 3 Cables per Conduit

AWG or MCM Full 1/3 Full 1/3 Full 1/3

2S* 2 2 3 3 3 1/2 3 1/2

2 2 2 3 3 3 1/2 3 1/2

1S* 2 2 3 3 3 1/2 3 1/2

1 2 2 3 1/2 3 3 1/2 3 1/2

1/0S* 2 2 3 1/2 3 3 1/2 3 1/2

1/0 2 2 3 1/2 3 1/2 3 1/2 3 1/2

2/0 2 2 3 1/2 3 1/2 4 4

3/0 2 2 4 3 1/2 4 4

4/0 2 1/2 2 4 4 5 4

250 2 1/2 2 1/2 5 4 5 5

350 2 1/2 2 1/2 5 5 5 5

500 3 5 6

750 3 6 6

1,000 3 1/2 6 6

* S = Solid ConductorNote. Table 9.12 is based on NEC requirements. Maximum conduit fill is 53 percent for one cable, 31 percent for two cables,

and 40 percent for three cables in a conduit. Unless noted, conductors are concentric stranded. If different conductors,such as compressed or compacted, are used, see Equation 9.1 for method of calculating. Outside diameters are basedon ICEA Publication ANSI/ICEA S-94-649-2000.

TABLE 9.12: 220-Mil Primary Cable.



25-kV Cable—260-Mil Insulation Wall, Concentric Neutral Construction




1S* 2 2 3 3 3 1/2 3 1/2

1 2 2 3 1/2 3 1/2 3 1/2 3 1/2

1/0S* 2 2 3 1/2 3 1/2 3 1/2 3 1/2

1/0 2 2 3 1/2 3 1/2 3 1/2 3 1/2

2/0 2 2 3 1/2 3 1/2 4 3 1/2

3/0 2 2 4 3 1/2 4 4

4/0 2 1/2 2 4 4 5 4

250 2 1/2 2 4 4 5 5

350 2 1/2 2 1/2 5 5 5 5

500 3 5 5

750 3 6 6

1,000 3 1/2 6 #

* S = Solid Conductor# Indicates that a 6-inch conduit is not of sufficient size to accommodate three cables of this size without exceeding the

maximum fill requirement.Note. Table 9.13 is based on NEC requirements. Maximum conduit fill is 53 percent for one cable, 31 percent for two cables,



324 – Sect ion 9


34.5-kV Cable—345-Mil Insulation Wall




1S* 2 2 4 4 4 4

1 2 2 4 4 4 4

1/0S* 2 1/2 2 1/2 4 4 5 5

1/0 2 1/2 2 1/2 4 4 5 4

2/0 2 1/2 2 1/2 5 5 5 5

3/0 2 1/2 2 1/2 5 5 5 5

4/0 2 1/2 2 1/2 5 5 5 5

250 3 2 1/2 5 5 6 5

350 3 3 6 5 6 6

500 3 6 6

750 3 1/2 6 #

1,000 3 1/2 # #

* S = Solid Conductor# Indicates that a 6-inch conduit is not of sufficient size to accommodate two (or three) cables of this size without exceeding

the maximum fill requirement.Note: Table 9.14 is based on NEC requirements. Maximum conduit fill is 53 percent for one cable, 31 percent for two cables,



MANHOLE TYPESIn the design or selection of manholes to use witha conduit system, there are many factors to con-sider. The enclosure must be structurally adequateto withstand the loads in the selected location.The manhole must also provide reasonable ac-cess to the conduit system with room to pulland splice cables. It should also provide spaceand facilities to properly mount cables and stillallow access and working room.

The location of manholes is one of the firstthings to carefully consider when designing theduct system. Previous statements have emphasizedthe location of manholes relative to load centersor based on cable-pulling limits. Accessibility and

safety of manhole location is also a major con-sideration. If possible, manhole entrances shouldbe located outside the paved roadway to mini-mize the hazard to workers and inconvenienceto the public while the manhole is open. Theroadway within street intersections should beparticularly avoided, if possible. However, if aduct line is installed in a roadway and there isan intersection with another duct line, doing somay be impossible. The location of existingwater, sewer, storm drain, and communicationlines will strongly influence the location of elec-tric facilities and may force location within theroadway. See Figure 9.4 for examples of pre-ferred manhole and duct line locations.


9Minimum Size of Conduit Necessary to Accommodate 600-Volt Secondary Underground Power Cablel

Minimum Conduit Size (Inches) for Numbers of Secondary Cables, Based on Insulation Construction

Conductor 1 Cable per Conduit 2 Cables per Conduit 3 Cables per Conduit 4 Cables per Conduit

AWG or MCM Regular Ruggedized Regular Ruggedized Regular Ruggedized Regular Ruggedized

4S* 2 2 2 2 2 2 2 2

4 2 2 2 2 2 2 2 2

2S* 2 2 2 2 2 2 2 2

2 2 2 2 2 2 2 2 2

1S* 2 2 2 2 2 2 2 2

1 2 2 2 2 2 2 2 2

1/0S* 2 2 2 2 2 2 2 2

1/0 2 2 2 2 2 2 2 2

2/0 2 2 2 2 2 2 2 2

3/0 2 2 2 2 2 2 2 2 1/2

4/0 2 2 2 2 2 2 2 1/2 2 1/2

250 2 2 2 2 1/2 2 1/2 2 1/2 2 1/2 3

350 2 2 2 1/2 2 1/2 2 1/2 3 3 3

500 2 2 3 3 3 3 3 1/2 3 1/2

* S = Solid ConductorRegular = Normal insulationRuggedized = Ruggedized, two-layer insulation. See Table 9.11 for more information.Note. Table 9.15 is based on NEC requirements. Maximum conduit fill is 53 percent for one cable, 31 percent for two cables, and 40 percent for

three cables in a conduit. Unless noted, conductors are concentric stranded. If different conductors, e.g., compressed or compacted, areused, see Equation 9.2 for method of calculating. Outside diameters are based on ICEA Publication ANSI/ICEA S-94-649-2000.

TABLE 9.15: Conduit Fill—Secondary Cable.

Access to the manhole is provided through aring and cover assembly. Covers are usually round.Noncircular covers should not be used without dueconsideration of the fact that such covers can fallinto the manhole. The minimum clear dimensionfor a cover is 26 inches. However, on electric man-holes, the clear opening should be a minimum of30 inches to not only ease access but also providemore room to maneuver cables during the pullingprocess. Covers of 36-inch diameter (or more)allow even more room; however, crews often findthat the added weight of these units is a con-cern. In addition to having adequate cover size,

the chimney between the top of the manhole andthe cover should have walls without protrusionsthat could injure personnel or damage cable.

Manholes may be divided into three generalcategories. The first type is used for locations instraight conduit runs where access is desired mainlyfor cable pulling. The second type is for locationswhere duct lines may intersect at an angle near45° or where a more narrow intersection man-hole is needed. The third type is designed to ac-commodate the intersection of two major ductbanks. These patterns are illustrated in Figure 9.5.Each has advantages in the location of cables.

326 – Sect ion 9

In the past, some electric utilities, particularlythose in urban areas, located special switchingand/or fusing equipment in manholes. However,this practice should be avoided because of thecongestion and safety problems it causes. In ad-dition, all switches used in manholes must besuitable for remote operation from outside themanhole. All these factors make installation ofpad-mounted switchgear much more practical.Here, equipment is more accessible for mainte-nance and operation. Moreover, personnel areworking at ground level with less restricted exitpaths in case of equipment problems.

MANHOLE/PULL BOX CONSTRUCTIONManholes and pull boxes must be designed tosustain all expected loads that may be imposed onthe structure. The manhole or pull box must becapable of withstanding vertical and horizontallive loads, dead loads, equipment loads, impactloads, loads caused by water table or frost, shear,and bending moments. Careful consideration

should be given to the location of the structureand loads that may be encountered. In roadwayareas, heavy trucks may subject the structure toextreme live loads and forceful impacts. In in-dustrial areas, large cranes may travel over ornear the manhole and create extreme pointloads when their outriggers are extended. Liveload requirements should be increased by 30percent to account for impact forces. The fol-lowing publications should be referenced whenload requirements are analyzed:

• Federal Specification RR-F-621D;• AASHTO Standard Specifications for Highway

Bridges, 1983;• National Electrical Safety Code, Section 32;

and• RUS Bulletin 1753F-151.

Another facet of manhole/vault design is al-lowance for uplift on the structure when the sur-rounding soil is saturated. If the manhole is well

9

FIGURE 9.4: Preferred Location of Duct Lines in Roadways. FIGURE 9.5: Typical Manhole Configurations.

Undesirable Duct andManhole Location

(a) Tap Manhole (b) Straight-Line Manhole

(c) Intersection Manhole

MainDucts

Tap Ductsto Load orTransformerLocation Main

Ducts

MainDucts

MainDucts

MainDucts

MainDucts

MainDucts

MainDucts

StreetStreet

Street

Street

Side

walk

Side

walk

Side

walk

Side

walk

Preferred Duct andManhole Location


9

FIGURE 9.6: Rectangular Manhole Construction Details.

328 – Sect ion 9

drained, the net buoyancy should be calculated.This force will have to be balanced by the effectiveweight of the overburden and soil shear acting onthe walls by saturated soil. Failure to take this intoaccount could result in a manhole floating outof the ground when the soil becomes saturated.This is not only extremely detrimental to systemreliability it is also quite disturbing to the public.

Figures 9.6, 9.7, 9.8, and 9.9 represent twostyles of manhole—rectangular and octagonal—with details indicating depth of install, personnelentrance duct interface, and other constructiondetails. Typically, precast manhole manufacturerscan supply these type of manholes and acces-sories that comply with industry standards.

Wall Thickness/Concrete Strength/Reinforcing SteelWhen precast manholes and pull boxes areused, the manufacturer will select the properconcrete strength, rebar type/spacing, and wallthickness based on the loading requirementssupplied by the purchaser. Most manufacturersuse Grade 60 reinforcing steel and 4,500 psiconcrete and design to current ASTM and ACIstandards. The purchaser should require themanufacturer to furnish load certifications sealedby a licensed professional engineer. Designguidelines for site-built manholes can be foundin Specifications and Drawings for Conduit andManhole Construction, RUS Bulletin 1753F-151.

9

FIGURE 9.7: Rectangular Manhole Installation Details.


9

FIGURE 9.8: Octagonal Manhole Construction Details.

330 – Sect ion 9

9

FIGURE 9.9: Octagonal Manhole Installation Details.

The purchaser should require the precastmanhole manufacturer to provide groundingprovisions so the reinforcing steel within thestructure walls can be connected to the systemneutral and grounding electrodes.

Conduit Entrances/KnockoutsMany precast manhole manufacturers provideknockout panels in each wall to accommodate awide variety of conduit and duct bank sizes.Knockout panels are typically three inches thick,void of rebar, and allow for quick tie-in of ductbanks and conduits.

Personnel/Equipment EntrancesAccess openings in manholes should be largeenough for workers to enter the manhole on aladder and to lower equipment needed for cablepulling, splicing, and testing. Manhole openingsshould be free of obstructions that would pre-vent the worker from safely and quickly exitingthe manhole. Large manholes may have morethan one entrance for convenience. Personnelaccess openings should not be located directlyover cables or equipment.

Manhole covers should be at least 30 inches indiameter and designed so they cannot fall into the


manhole and harm personnel or equipment. Per-sonnel access openings should be located wheresafe access can be provided and outside of pedes-trian traffic areas when possible. Manhole coversshould have markings to identify the type of utilityand ownership. Sufficient means through weight,design, or location should be employed to preventaccess by the public and unqualified persons.

Sump Pit/Drain LinesManholes should have adequate drainage to keepthem dry and free of standing water. In some loca-tions, a sump pit is designed in the manhole floor.The sump pit should be excavated two feetbelow the manhole floor and filled with smallstones to allow water to seep out of the man-hole. In high water table areas, the sump pit inthe floor would be ineffective. Of course, if thenatural water table is higher than the manholefloor, there will be a flow of groundwater intothe manhole with the potential for underminingof the structure.

In some cases, a drain in the manhole floormay be connected to a local storm sewer ifthere is no chance of the storm sewer backinginto the manhole during periods of high flow.However, the manhole drain must never be con-nected to a sanitary sewer since there is a dan-ger of sewer gas entering the electric manhole.

When a manhole drain is provided, the man-hole floor should be sloped to direct all accu-mulated water to the drain. Also, the exteriorwalls of the manhole or pull box may need tobe waterproofed in areas with a high water tableto minimize seepage through the walls. In ex-treme cases, manholes in an area routinely sub-ject to flooding may have automatic sumppumps to remove water.

Pulling Irons and Pulling EyesWhere pulling appurtenances are furnished,they should be installed with a safety factor oftwo (2.0), based on the expected load. Pullingirons can be supplied in galvanized steel orplastic coated steel. Pulling irons are used forlifting the roof and floor panels. Pulling eyesand inserts are available for lifting wall panels.The precast manufacturer can size the pullingeyes and pulling irons on the basis of the loadspecifications supplied by the purchaser.

Joint SealantsJoints in precast manholes are typically designedto be self-aligning during the assembly process.Some precast manholes also have cast-in-con-crete weld plates that, when welded together,prevent shifting of manhole sections and createa rigid assembly. Asphaltic butyl compounds areusually used in the joints to provide a water sealthat is resistant to temperature changes, shock,shrinkage, and mild chemicals. Sealant shouldcomply with Federal Specification SS-S-210A andAASHTO M-198B.

Ring and Cover Assemblies—SpecificationsRing and cover assemblies should comply withthe loading requirements of Federal SpecificationRR-F-621D. When specifying ring and covers,the interchangeability of new manhole lids withexisting manhole lids should be considered. Ifpossible, a standard for lid diameter, thickness,lettering, and so on should be enforced.

When future pavement overlays are expected,the vertical seat thickness of the manhole coverand available cast iron riser ring sizes must beconsidered. Bolted covers can eliminate man-hole cover blow-off caused by rising waters inlow lying areas. Manhole covers with watertightgaskets will keep surface water from flowinginto the manhole. The utility name and the typeof utility occupying the manhole should bespecified on the manhole cover. See NESC 323J.

Manhole Racks/Cable SupportsCable racks and supports must be installed inmanholes to support cables at joints and keepcables from lying on the manhole floor. TheNESC requires all cables to be at least threeinches off the manhole floor. Usually cable racksare placed six inches from the ends of cablejoints and every three feet around the manholefor general cable support. Cable racks are usuallyfastened to the manhole walls with expansionbolts, power-installed studs, or threaded inserts.

Metal cable rack/hook assemblies are availablewith plastic coatings to reduce corrosion and comein a variety of sizes. Metal cable racks should bebonded to the system neutral for safety. Cableracks are also available in fiberglass or othernonconductive materials that avoid corrosion andgrounding concerns. Cable racks should be in-

9

332 – Sect ion 9

stalled with provisions to allow for cable expan-sion and contraction in long duct runs duringload cycles. The use of sliding cradle insulatorsand generous radii on exit bends will preventdamage from abrasion during load cycles.

WaterproofingElectrical manholes may be “painted” on exteriorwalls with an asphalt-base, waterproof sealer toprevent water from seeping into the manhole. Inaddition, sealed covers, mentioned above, canbe used to reduce runoff from the road surface.

9

Cable Pulling Many utilities are encountering situations in whichthe best installation is cable installed in conduit.This type of installation may be a single, direct-buried conduit or a major, concrete-encased,multiple duct bank. Regardless of configuration,the cable must be installed in the conduit with-out incurring mechanical damage that will im-pair electrical performance or cable longevity.Therefore, analysis of the cable-pulling problemmust be performed during the design process.

The main limiting factors in cable pulling aretension and sidewall bearing pressure (SWBP).Tension must be limited to avoid overstressingthe metallic central conductor of the cable. It isassumed that the central conductor carries alltensile forces and these forces must be kept wellbelow the conductor yield point. The origin ofcable tension is friction between the outer sur-face of a cable and the inner surface of the con-duit. The force the cable exerts on the conduitwall and the coefficient of friction between thetwo surfaces governs the amount of friction.

Sidewall bearing pressure is the force appliedperpendicularly to the outer surface of the cablewhen it is being pulled through a bend orsheave. Excessive sidewall pressure will distortcable components, particularly the outer jacketand the insulation shield. In some cases, con-centric neutral wires or the tape shield may bepushed into the semiconducting insulationshield. More extreme cases may damage the in-sulating layer or its semiconducting shield. Allthese conditions involve severe damage to thecable structure and decreased cable life.

The overall cable-pulling problem may beconsidered as a combination of factors:

• Cable-conduit friction,• Cable weight,• Conduit bends,• Sidewall bearing pressure, and

• Allowable cable tension.

Each of these will be discussed separately todevelop a comprehensive analysis of the cable-pulling problem.

CABLE-CONDUIT FRICTIONThe most important factor in cable pulling is thefriction that exists between the outer surface ofthe cable and the inner surface of the conduit.This friction force for a horizontal pull is classi-cally expressed as shown in Equation 9.3.

Equation 9.3.

T = W × WC × f × l

where: T = Tension, in lb.W = Weight of cable, per unit of length,

in lb. per ftWC= Weight correction factor

(where required)f = Coefficient of frictionl = Length of cable, in feet

This relationship is illustrated in Figure 9.10.Equation 9.3 shows that, if there is no frictionbetween the cable and the conduit (f = 0), thereis no tension in the cable as it is being pulled.

Friction between the cable and conduit is avery complex phenomenon. Contributing factorsinclude the following:

• Surface roughness of both cable jacket andconduit,

• Deformation characteristics of jacket and con-duit materials as shear develops at interface, and

• Other materials, either dirt or lubrication, pre-sent at interface.


calculate the force required to keep a cablemoving in the conduit. Most pulling calculationsemphasize the dynamic coefficient because thecable should be continually in motion during thepulling process. This condition is the one mostcommonly encountered. However, tensions re-sulting from the static coefficient should alwaysbe considered because unforeseen circumstancesmay stop a pull at any point and the cable mustbe restarted.

The static coefficient of friction is used to cal-culate the tension required to initially move acable that is in a conduit. Static friction coefficientsare always higher than the dynamic coefficientsfor similar materials. The ratio of these valueswith conventional lubricants has been observedbetween 1.25 and 1.85. Tensions resulting fromthe static coefficient should always be consideredbecause unforeseen circumstances may stop apull at any point and the cable must be restarted.

The presence or absence of other materialsat the cable-conduit interface is also a majorcontributing factor to the tensions actually expe-rienced during the pulling process. This factorcan be either positive or negative. Most dirt isa strong negative factor because granules can

9

FIGURE 9.10: Cable/Conduit Friction and Pulling Tension.

In light of the complex nature of cable-conduitfriction, empirical tests are the only reasonableway to predict friction factors. The variability ofthese same factors also means that the apparentcoefficient of friction experienced during pullingmay also differ from values measured with thesame materials under similar circumstances. How-ever, the materials comprising the cable jacketand the conduit constitute the best factors forbeginning characterization of the friction coeffi-cient. Typical values of this coefficient are foundin Table 9.16.

Table 9.16 gives dynamic friction coefficients.The dynamic coefficient of friction is used to

Soap/Water Lubricants Polymer LubricantStraight Pulls (SWBP = 200 lb./ft)

One Cable Three Cables Bends (SWBP Static DynamicDuct Material Cable Jacket @75°C @75°C > 150 lb./ft) Friction Friction

PVC XLPE 0.40 0.60 0.15 0.14 0.11

PE 0.40 0.45 0.15 0.14 0.11

PVC 0.50 0.60 0.30 0.17 0.12

Concentric Neutral 0.40 N/A Not Recommended N/A N/A

Steel XLPE 0.60 0.65 0.25 0.15 0.14

PE 0.50 0.55 0.25 0.11 0.11

PVC 0.65 0.70 0.30 0.15 0.15

Concentric Neutral 0.50 N/A Not Recommended N/A N/A

Note. Use straight-pull values for bends with sidewall bearing pressure (SWBP)<150 lb./foot.For other conduit or cable jackets, see AEIC G5-90; EPRI EL-3333, Vol. 2; or lubricant manufacturer test data.Polymer lubricant is American Polywater J. Others may vary.N/A = Not Applicable

TABLE 9.16: Recommended Dynamic Friction Coefficients for Straight Pulls and Bends UsingSoap/Water or Polymer Lubricants.

Inner Conduit Wall

Friction (f) Friction (f) Friction (f)

Tension T2T1

Direction of Pull

T2 = T1 + (f × w)

Cable Weight (w)

lubricant works will dependnot only on a low internalshear value but also on howwell the film is maintained,especially under the pressureof bends.

The technology of cable lu-bricants is continually advanc-ing. Product types includepetroleum jelly, soap-and-water mixtures, and polymermixtures. Selection of a cablelubricant should consider theexpected coefficient of fric-tion, long-term compatibilitywith the cable jacket, flamma-bility, and adhesion of cableto conduit after the lubricantdries. The best combination of

properties currently offered seems to be by poly-mer-based lubricants. However, this is subject tochange as lubricant technology advances.

CABLE WEIGHTEquation 9.3 shows that pulling tension is di-rectly proportional to cable weight. For simplecases of straight runs with a single cable, this isgenerally true. Weight is a consideration be-cause, in simple cases, it is the major contribut-ing element to the force exerted on the conduitby the cable.

However, in the practical case of multipleconductor runs, other considerations warrant theuse of a weight correction factor, WC. This factordepends on the configuration of cables in con-duit. For a single cable in conduit, WC = 1.0.However, if multiple cables are present in a con-duit, the values will be shown by the followingtwo equations. Equation 9.4 shows the valuesfor a cradled configuration as well as the valuesfor a triangular configuration.

Figure 9.11 illustrates the cradled and triangu-lar cable configurations.

For pulling calculations, the total weight of allcables in the conduit must be considered. Forexample, if three cables are being pulled in oneconduit and each weighs 1.5 pounds per foot,the resulting cable weight (W) will be 4.5 lb./ft.Cable weight is given in general data sheets.

334 – Sect ion 9

partially embed themselves ineither the cable jacket or theconduit wall, or both. Whenthis happens, simple slidingfriction is changed to a processthat scores the jacket and con-duit surfaces. This process notonly damages the surfaces butalso produces much higherfriction forces. Therefore, onebasic requirement is to haveall conduit clean beforepulling begins.

A beneficial effect can beachieved by introducing andmaintaining a lubricant be-tween the surfaces of the cableand conduit. Lubricants pro-duce a film of slippery materialbetween the surfaces. The film will have verylow internal shear values compared with thebare friction of the surfaces and, therefore, thecable-pulling tension will be less. How well the

9Use the static

coefficient of friction

in cable-pulling

calculations.

No amount of

lubricant can

compensate for even

small amounts of dirt

in a conduit.

FIGURE 9.11: Cable Configurations in Conduit.

WC = 1–2 –0.5d

(D – d)WC = 1 +

243

d(D – d)

Equation 9.4.A Equation 9.4.B

3 Cables Cradled 3 Cables Triangular

where: Wc = Weight correction factorD = Conduit inside diameter, in inchesd = Cable outside diameter, in inches

Clearance = C

Three Cables—Triangular Three Cables—Cradled


However, for critical cable-pulling calculations,the specific cable manufacturer should be con-sulted for confirmation or more exact information.

SLOPED PULLSEquation 9.5 applies only to straight horizontalcable pulls. For sloped conduit installations, dif-ferent tension equations apply. Equation 9.5.Aapplies for upward slopes, and Equation 9.5.Bfor downward slopes. These equations reflectthe additional tension needed to pull the weightof the cable upward and the reduced tension re-sulting from the assistance of gravity when thecable is pulled downward. The path of the cableis assumed to be a straight line.

In the case of a vertical pull, the value of θ inEquations 9.5.A and 9.5.B is 90°. The expressionsin parentheses in the equations then become +1for upward vertical pulls and -1 for downwardvertical pulls.

9CONDUIT BENDSCable pulling would be much simpler if all con-duit runs were straight. However, bends are nec-essary and, in many cases, cause very largeincreases in cable-pulling tensions. Bends alsocause compressive stresses on the cable as it ispulled through the bend. This force is referredto as sidewall bearing pressure (SWBP) and candamage the cable insulation and shielding systems.

Regardless of the length of a cable run or typeof cable, the sum of all bends in a run shouldnever exceed 270°. For example, that could betwo 90° vertical bends and one 90° horizontalbend. Gradual changes in conduit direction thatdo not have a sweep bend fitting or an elbowshould also be included in observing this limit.In most cases, the calculated pulling tension forpower cables will be exceeded before the 270°limit is reached.

The effect of conduit bends not only is a func-tion of the angle turned but also strongly de-pends on the inside radius of the conduit bend.Table 9.17 gives the inside radius for typicalbends available for PVC and steel conduit.

When planning conduit installations, the engi-neer must consider the minimum bending radiusof cables. This minimum cable bending radius isdetermined by the cable construction and is gen-erally given as a multiple of the cable outside di-ameter. If the minimum cable bending radiusrequirement is not met, the shielding and insula-tion systems of the cable may be damaged evenif pulling tension and SWBP are low. Conduitbends must never be installed with an inside ra-dius less than the minimum bending radius ofthe largest cable anticipated for installation inthat location.

The minimum bending radius for most com-monly encountered shielded distribution cablesis 12 times the outside diameter. For example, a350-kcmil shielded power cable with an outsidediameter of 1.6 inches should always have abending radius of more than 12 times its outsidediameter, or a minimum bending radius of 19.2inches. Information in Table 9.17 shows that thiscable should not be installed in a two-inch con-duit bend with a radius of 18 inches. It would alsobe close to limits if it was installed in either a two-or four-inch conduit with a 24-inch sweep radius.

Equation 9.5.A Equation 9.5.B

where: T = Tensionl = Length of cableW = Weight of cable, per unit of lengthf = Coefficient of frictionWC= Weight correction factor (where required)θ = The angle of the slope measured from the

horizontal, in degrees

T = l × W × (f × WC × cosθ + sinθ) T = l × W × (f × WC × cosθ – sinθ)

Duct I.D. Bend Centerline RadiusDuct Size (Inches) 18" 24" 30" 36" 48"

2 2.067 1.41' 1.91' 2.41' 2.91' 3.91'

4 4.026 — 1.82' 2.33' 2.83' 3.83'

5 5.047 — — 2.29' 2.79' 3.79'

6 6.065 — — — 2.75' 3.75'

TABLE 9.17: Inside Bend Radius for 90° Schedule 40 Conduits.

336 – Sect ion 9

As underground conduits generally do nothave the space limitations encountered by in-building wiring, the largest practical radiusshould be used on all bends. Most utilities stan-dardize on 36-inch radius bends for duct banks.If more than one conduit size is being used in aduct bank, all sizes must have the same radius.

The amount of increase in pulling tension thatresults from pulling around conduit bends canbe calculated from Equation 9.5.C.

Equation 9.5.C is a simplified equation thatshould be adequate for most practical cases. Theamount of error is not likely to exceed approxi-mately 15 lb. of tension for each bend.

SIDEWALL BEARING PRESSURESWBP is a measure of the compressive force ap-plied perpendicular to a cable surface by theinner wall of a conduit bend (see Figure 9.12).The SWBP depends on the tension in the cableat that point and the radius of the bend. Equa-tion 9.6 defines SWBP for the simple case of asingle cable in a conduit bend. Equation 9.7 de-fines the SWBP for three cables in a cradledconfiguration. If the cables assume a triangularconfiguration, Equation 9.8 applies.

In equations 9.6 through 9.8, T2 is the cabletension at the exit of the bend, R is the insideradius of the bend in feet, and WC is the appli-cable weight correction factor for the particularcable configuration. See Equations 9.4 and 9.5.

SWBP will distort the cable cross-section. IfSWBP is excessive, it will permanently damagethe cable structure. This damage may be a crushedmetallic shield, indentation of the semiconductingshield, or mechanical failure of the insulation.All these conditions will lead to shortened cablelife, if not immediate failure. The allowable lim-its of SWBP for various cable types are given inTable 9.18. This information was developed un-der Electric Power Research Institute (EPRI) Pro-ject EL-3333 in 1984. These values are higher thanpreviously recommended by cable manufacturers

9T2 = T1×ef × WC × θ

where: T2 = Tension at exit from bendT1 = Tension at entrance to bende = 2.71828f = Coefficient of frictionWC= Weight correction factorθ = Angle of bend, in radians (1 radian = 57.296 degrees)

Equation 9.5.C

FIGURE 9.12: Sidewall Bearing Pressure.

TensionBeforeBend T1

Tension AfterBend T2

InnerConduitWall

Direction of Pull

SWBP =

SWBP results from cable tension in bends and creates additional pulling tension.

T2 (lb.)Inside Radius of Conduit Bend

Inside

Radius (R)ofConduitBend

Equation 9.8

SWBP = (three cables triangular)WCT22R

Equation 9.6

SWBP = (single cable)T2R

Equation 9.7

SWBP = (three cables cradled)(3WC – 2)T2

3R

dependent on the bend con-figuration, the soil characteris-tics, and the degree ofcompaction. High-tensioncable pulls should never beattempted through bends indirect-buried conduit.

Another concern with un-supported bends in direct-buried conduit runs is thepossibility of burn- through bypulling cables or ropes. Burn-through results from frictionalheat build up at the inner sur-face of the conduit bend. Thiscondition is much less likelywhen steel pulling lines areused instead of ropes. Burn-through will always result inextensive cable damage or a

jammed conduit. Burn-through is not a problemwhere rigid steel bends are used and it is signifi-cantly reduced by the use of fiberglass reinforcedepoxy (FRE) bends.

JAM RATIOWhen three single cables are pulled in parallelin a conduit, wedging action may develop inbends. This is caused by cables changing from atriangular configuration to a cradled configura-tion as they are pulled through the bend. Thischange in configuration will force the two outercables further apart. If the conduit diameter istoo small to accommodate this wider configura-tion, the cables will become jammed in the bend.

The jam ratio (J) must be checked to predictthis phenomenon. The jam ratio is simply theratio of the cable diameter to the conduit insidediameter given in Equation 9.9.

Either measure or refer to the manufacturer’sliterature for the cable outside diameter. The in-side diameter of typical conduit sizes may befound in Table 9.17.

When the jam ratio is calculated, the probablecable configuration in the conduit can be deter-mined. A listing of probable configurations isgiven in Table 9.19. (See Figure 9.11.)

Experience has shown that cable jamming ismost likely between J = 2.5 and J = 3.0. This is


but represent the result of anextensive cable installationtesting program.

One cautionary note is thatthe SWBP values in Table 9.18are for concrete-encased ductor rigid steel conduit that iswell supported in bends. Itmay be necessary to provideconcrete encasement in theimmediate area of a bend inorder to achieve adequatesupport. If cable pulls ap-proaching the limits of Table9.18 are attempted through di-rect-buried conduit, the bendsmay collapse or move withdisastrous results. Not onlywill the duct rupture, but thecable will be cut and jammed.Limiting SWBP values cannot be given for di-rect-buried conduit because they are highly

9If SWBP is excessive,

permanent damage

to the cable structure

will occur.

High-tension cable

pulls should never

be attempted through

bends in direct-buried

conduit.

Cable Construction Type Maximum SWBP (lb./ft)

XLPE Insulation - 600V Cable 1,200

• PE and XLPE insulation, concentric wire shield:• Without jacket, single conductor 1,200• Without jacket, three conductors 750• With encapsulating jacket 2,000

PE and XLPE insulation, LC shield, LDPE jacket 1,500

PE, XLPE, EPR insulation, concentric wire or tape 2,000shield, LDPE and PVC sleeved jackets

Note. LDPE = low-density polyethylene; MDPE = medium-density polyethylene.

TABLE 9.18: Recommended Maximum Sidewall Bearing Pressures.Source: EPRI EL-3333 (1984).

J =

where J = Jam ratioD = Conduit inside diameterd = Outside diameter of single cable

Equation 9.9

Dd

338 – Sect ion 9

particularly true if the SWBP in a bend exceeds1,000 lb./ft. Therefore, this combination of con-ditions must be avoided. The most obviousmethod to prevent jamming is to always use aconduit with an inside diameter at least threetimes the outside diameter of the cable beingpulled. Doing so is often not practical, especiallywith high-ampacity distribution class cables.Therefore, the jam ratio must be calculated, andthe range of J = 2.5 to J = 3.0 should be avoided.

As mentioned earlier, cable jamming doesoccur in bends. It is generallynot a problem in straight pulls.The cable will assume the con-figuration indicated by Table9.19 and remain in that config-uration throughout the pull. Inaddition, cables that aretriplexed (twisted) before en-tering the conduit will tend tomaintain the triangular config-uration through the bends. Be-cause they will not change to the cradledconfiguration, jamming will be avoided.

9

Jam Ratio Range Cable Configuration

J<2.4 Triangular

2.4–2.6 More likely triangular

2.6–2.8 Either triangular or cradled

2.8–3.0 More likely cradled

J>3.0 Cradled

TABLE 9.19: Cable Configuration for VariousJam Ratios.

CLEARANCE FACTORThe clearance between the upper cable and thetop of the conduit should always be checked todetermine the size conduit required for a givencable configuration. This clearance (C) is illus-trated in Figure 9.11. For a single cable in a con-duit, the clearance is obviously the differencebetween the inside diameter of the conduit andthe outside diameter of the cable. If the allow-able variation in cable diameter of five percent istaken into account, the expected clearance is ex-

pressed by Equation 9.10.When three cables are

pulled into a conduit, they as-sume either a triangular or acradled configuration. How-ever, because clearance is aproblem only as the cableapproaches the maximumconduit capacity and the ca-bles are always triangularwhen the conduit fill is high,

clearance needs to be calculated only for thetriangular configuration. Equation 9.11 givesclearance under this condition.

After calculating the expected clearance, makesure that it is at least 0.5 inches or greater. Thismuch clearance is needed to allow for possibleconduit variations. If the upper cable contactsthe top of the conduit, the cable will jam.

CABLE-PULLING EYE TENSION LIMITSThe preceding discussions have covered manyof the factors affecting the expected tension. Theobjective of the calculations has been to avoidoverstressing cable during the pulling operation.The practical limit for cable tension is based notonly on cable tensile stress but also on stressesin the connection point of the pulling wire (orrope) and the cable. Table 9.20 shows the allow-able tension based on various pulling eye typesand the conductor in the cable being pulled. FromTable 9.20, it is determined that a 350-kcmilaluminum cable with an aluminum compressionpulling eye can accommodate a tension of up to2,800 lb. (350,000 cm × 0.008 lb./cm).

If three cables are pulled in a single conduit,allowances must be made for unequal sharing ofthe total tension. It is generally assumed that, on

Equation 9.11

C = D – 1.05d

Equation 9.10

C = – 1.434d + 0.5(D – 1.05d) 1–2 0.5D

21.05d

D – 1.05d

Clearance must be

maintained or the

cable will jam in

the conduit.


three-conductor pulls, only two of the cables ac-tually develop tension. Therefore, the total ten-sion of the three cables must be divided by twoto establish the expected tension in each cable.This assumption must be applied to pulling eyeload calculations.

If cable is pulled with basket-type grips in-stead of pulling eyes, lower tension limits applybecause of the mechanical stresses that are

9

AluminumCompression Solder Filled Epoxy Filled

Conductor (lb./cmil) (lb./cmil) (lb./cmil)

Copper (annealed) 0.011 0.013 —

Aluminum-solid 0.006 N/A 0.008(1/2 to full hard)

Aluminum-stranded 0.008 N/A 0.011(3/4 and full hard)

N/A = not applicable

TABLE 9.20: Recommended Maximum Pulling Tension Stress forPulling Eyes on Copper and Aluminum Conductors. Source: EPRIEL-3333 (1984).

imposed on the cable insulation, shield, andjacket by the grips. Table 9.21 gives the limits forpulling single and multiple cables with variousgrip arrangements.

Cable-pulling grips must be used carefully andin strict accordance with the grip and cable man-ufacturers’ instructions. Grips must be attachedwith provisions to maintain grip compressioneven if the tension drops to zero. Cable undergrips and for a distance of at least two feet be-yond the end of the grip must be cut off anddiscarded. In addition, basket-type grips must beof a type specifically designed for pulling insu-lated cable because of the characteristics of theinsulated cable and its behavior under the com-pressive forces developed by the basket grips.Grips generally used for cable support at riserpoles are not satisfactory for cable pulling.

Special split-basket cable grips are sometimesconnected to cables in intermediate manholes topull slack in these locations. Because of the con-struction of these devices and the fact that cableunder the grips cannot be cut out, tension onthese grips should be limited to 1,000 lb. If

Three Cables in Three Cables (OneCable Construction Type Single Cable (lb.) One Grip (lb.) Grip per Cable) (lb.)

XLPE insulation—600-V cable 2,000 2,000 4,000

EPR and Neoprene—600-V cable 2,000 2,000 4,000

PE and XLPE insulation, concentric wire 10,000 5,000 20,000shield, with and without encapsulatingjacket—all voltages

PE and XLPE insulation, L.C. shield, LDPE 8,000 4,000 16,000jacket—15-, 25-, and 35-kV cable

PE and XLPE insulation, concentric wire 10,000 5,000 20,000or tape shield, LDPE and PVC sleevedjackets—all voltages

EPR insulation, concentric wire or tape 10,000 10,000 20,000shield, LDPE and PVC sleeved jackets—all voltages

XLPE insulation, copper wire or ribbon 18,000 9,000 36,000shield, MDPE sleeved jacket—all voltages

* Conductor tensions must not exceed values calculated from Table 9.20.

TABLE 9.21. Recommended Maximum Pulling Tension Limits for Basket-Type Pulling Grips.*Source: EPRI EL-3333 (1984).

340 – Sect ion 9

higher levels of tension are expected, the cablemanufacturer should be contacted for recom-mendations before this work is attempted.

CABLE-PULLING CALCULATION SEQUENCEAs described above, several factors determinecable tensions during the pulling process. In ad-dition, many of these factors influence not onlythe pulling tension but also other factors in thepulling process. For example, the friction en-countered in the first straight section of conduitwill mean higher entering tension in the firstbend. This tension on the cable entering thebend will contribute to higher SWBP in thebend and a higher tension contribution from thebend. Therefore, tension calculations must beorganized to follow the same sequence as theactual field pull. Prior organization of essentialdata will also enhance the calculation process.The following sequence of steps will yield thegreatest efficiency in the calculation process.

STEP 1: Determine cable characteristics:• Weight• Diameter• Outer jacket material.

STEP 2: Determine duct characteristics:• Material• Diameter.

STEP 3: Determine friction factors for a givencombination of cable outer jacket mate-rial and conduit composition. Considerthe lubrication to be used and the effectof higher SWBP in bends.

STEP 4: Calculate the jam ratio, clearance factor,and weight correction factor. If threecables are being pulled in one conduit,determine whether the cable configura-tion will be triangular or cradled.

STEP 5: Determine cable limits including maxi-mum allowable tension, maximumallowable SWBP, and minimum bend-ing radius.

STEP 6: Calculate the tension in each conduitsection progressing from reel end towinch end. Determine if tensions andSWBP limits are met in each section.Consider the limitations of the cable-pulling equipment. Use the ending

tension (T2) in each section as thebeginning tension (T1) in each succeed-ing section.

In most actual conduit runs, especially thosewith more than one bend, calculating pullingtensions in each direction will be beneficial. Of-ten it will be found that factors such as conduitslope or the combination of bend locations willgive lower pulling tensions if a particular direc-tion of pull is used. In simple cases, such as astraight downhill pull or a pull with a singlebend near one end, the best pulling directionmay be obvious. However, as conditions growmore complex, examination of both pull direc-tions will be beneficial. In addition, field accessconditions may force installation crews to strong-ly consider the alternative pulling direction, andprior calculation of the expected tensions willsimplify their decision-making process.

Under any conditions, cable installation crewsmust be instructed to always use the specific di-rection of pull shown on project drawings unlessprior consideration of the alternative directionhas shown it to be acceptable. See Appendix Jfor several example calculations for selectedcable pulls that outline the methodology to beused in evaluating the cable-pulling limitations.

CABLE-PULLING SOFTWAREAlthough the methods described in this manualand referenced documents will allow calculationof expected pulling tensions, extensive pullingcalculations can be simplified by using one ofthe calculation programs designed for use on apersonal computer. Spreadsheet calculation pro-grams might also be used, but the relatively lowcost of currently available cable-pulling pro-grams makes them the preferred approach.

The engineer using a computer-based pulling-tension program must recognize that a compre-hensive program will require detailed knowledgeof all cable and conduit parameters as well asaccess limitations. A pulling-tension program is atool to simplify the calculation process, not asubstitute for knowledge of expected field con-ditions. Data must still be accumulated and thepulling process organized in a logical fashionbefore calculations begin.

9


The use of cable-pulling software is recom-mended on complex pulls or those that mayclosely approach allowable tension limits. Onesuch software program is Cable Pulling Assistant(CPA) that was developed by General ElectricCompany as part of its Distrib-ution Systems Testing, Appli-cations, and Research (DSTAR)program. This is availablethrough Cooperative ResearchNetwork (CRN). Another pop-ular program, “Pull Planner2000 for Windows,” has beendeveloped by American Poly-water Corporation.

Regardless of the source ofthe software, it is incumbenton the user to confirm the val-ues used for coefficient-of-fric-tion, allowable sidewallbearing pressures, allowable cable tension, and

other values critical to accurate pulling calcula-tions. Default values provided in software pack-ages may not be completely applicable to yourparticular materials or pulling configuration.

Software allows the convenient examinationof multiple actions and en-sures consistent calculation ac-curacy if data are enteredcorrectly. The better softwarepackages also use more exactequations for pulling tensions,especially in more complexconduit arrangements. This ex-actness should yield greateraccuracy with the same efforton the user’s part. However,even with the most advancedsoftware, the results are onlyas accurate as the data that areentered; good judgment must

still be used in applying the results.

9

A cable pulling-

tension program is

a tool to simplify the

calculation process,

not a substitute for

knowledge of expected

field conditions.


1. Conduit should be used wherever additionalcable protection is required or the deferralof future excavation costs will justify theadditional initial expense.

2. The sum of all bends in a cable run shouldnever exceed 270°.

3. High-tension cable pulls should never beattempted through unsecured bends indirect-buried conduit.

4. The types of cable circuits to be installedwill determine the conduit system design.

5. Manholes and/or splice boxes will provideconvenient access points to conduit systemsand are useful for cable pulling and splicing.

6. Cable pulling should be planned as partof the conduit system design process.

7. Limits on cable tension and SWBP shouldbe observed to avoid cable damage.

8. The expected pulling direction and allfield conditions must be considered incable-pulling calculations. Detailed cable-pulling instructions must be provided tofield crews.

9. Cable under basket-type pulling gripsmust always be discarded.

Jo ints, Elbows, and Terminat ions – 343

Joints, Elbows, andTerminations10

Application ofJoints, Elbows,and Terminations

In This Section:

On new and existing underground distributionsystems, it is routinely necessary to join cablesto provide continuous lengths and reconnect ca-bles where a service failure has occurred. Thisjoining or reconnection is accomplished byjoints; typical designs are given in this sectionfor primary and secondary cables. ANSI andIEEE standards use the word joint as standardterminology in lieu of the word splice, but thetwo terms mean the same thing. This section iswritten using the ANSI/IEEE terminology.

Every cable circuit must have at least twopermanent terminations, one at each end ofthe circuit. In secondary circuits, a terminationis required for mechanical support of the ca-ble, connection to equipment, and physical pro-tection of the insulation and conductor, particu-larly against entry of water into the conductorinterstices. In primary circuits, in addition, thetermination must reduce the radial and longitu-dinal electrical stress between the conductor andground. This reduction is accomplished by meansof stress cones or other stress-control devices.

In primary circuits, elbows are used at trans-formers, junctions, and switches to terminate asection of the cable circuit. With this type ofcable termination, the cable can be disconnected

and reconnected to the apparatus without dis-turbing the cable structure. Typical elbows incommon use and their application are describedin this section.

Also within cable circuits, separable joints andelbow connectors are sometimes used to join ca-bles, provide branch circuits, and make separableconnections at apparatus for additional circuits.The types and applications of separable connec-tors are discussed.

A typical primary UD circuit begins at a sub-station or from an overhead line where there isa transition to an underground cable. The pri-mary cable extends down a structure and intothe ground to the first piece of equipment or ap-paratus, or it may have a joint to extend thecable run. A typical secondary circuit begins atthe distribution transformer (or pedestal), runsunderground, and emerges at the meter base lo-cated on the consumer’s premises.

Under RUS standards, joints, elbows, and ter-minations are designed to be installed on ap-proved primary cables rated for 15-, 25-, or 35-kVservice. At present, industry standards providefor two classes of primary cable accessories.These general classes have continuous currentratings of 200 and 600 amperes. The actual circuit

Application of Joints, Elbows, and Terminations

Joints, Elbows, and Terminations for 200-Ampere Primary Circuits

Joints, Elbows, and Terminations for 600-Ampere Primary Circuits

Joints and Terminations for Secondary Circuits


344 – Sect ion 10

current, however, will be governed by the cir-cuit conductor size and circuit breaker rating. Ifthe circuit has a small conductor size, such asNo. 2 or 1/0 AWG, a 200-ampere componentcan be used. Normally, a 200-ampere compo-nent is used because it is more economical andis available with load-break capabilities. If thecircuit will carry close to 200 amperes, it may bepreferable to use a 600-ampere component be-cause the larger component will run cooler,which is desirable, and because future loads

10may go above 200 amperes. Typically, 200-am-pere components can be used on phase conduc-tors up to 4/0 stranded AWG. Also, 600-amperecomponents can be used on cables 4/0 strandedAWG and larger. Components rated for 600 am-peres should always be used when the circuitexceeds 200 amperes.

For secondary 600-volt circuits, joints and termi-nations are designed for the same current rating asthat of the cables to which they are attached.

Joints, Elbows,and Terminationsfor 200-AmperePrimary Circuits

CABLE JOINTSDesign Features of JointsRUS-approved joints may be premolded, coldshrink, or heat shrink. Taped joints are not ap-proved. When two cables are joined, the lengthof the insulation between the conductor and in-sulation shields must be made greater than theradial thickness of the insulation because the in-sulation surface will not support voltage stress.

Therefore, the path between the conductor andthe insulation shields is increased by the re-moval of the insulation shields and outer cover-ings for a specified distance. When this is done,the leakage path between the conductor and in-sulation shields is greater; however, the voltagegradient increases abruptly along the insulationsurface at the edge of the insulation shield (seeFigure 10.1). Figure 10.2 represents a premolded

Conductor

Insulation

100

80

Equipotential Lines

InsulationShield

Shown by equipotential lines at the end of the removed insulationshield. Values shown are a percentage of total voltage.

Connector

Conductor

Equipotential Lines

0

Insulation ShieldCable Insulation

Joint HousingShield

50

30

15

FIGURE 10.1: Voltage Stress Concentration.

Equipotential values are a percentage of total voltage.

FIGURE 10.2: Voltage Stress Distribution in a TypicalPremolded Joint Housing.

102030405060708090

100


joint housing cross-section showing the voltagestress distribution along the body of the joint in-sulation. This reduces the voltage gradientacross the insulating components and increasesthe resistance of the joint to failure.

Before molded or heat-shrink joint designs,joints consisted of hand-wrapped layers of insu-lating tapes to a predetermined contour whichwas commonly referred to as a pencil. For elec-trical integrity and watertightness, these jointswere highly dependent on the skill of the splicer.A shielding tape was wrapped over the conduc-tor connector smoothly with no creases or sharpprojections. The cable insulation was tapered(pencilled) to allow the insulating tapes to bewrapped to a smooth contour with minimum airgaps. The tape for the insulation shielding waswrapped over the insulation with minimumcreases. The concentric neutral was spliced witha copper jumper wire. It is easy to see how diffi-cult it was to fabricate a good, long-lived cablejoint, particularly in a splicing pit in the rain! RUSdoes not currently approve taped joints, eithertemporary or permanent.

Premolded Permanent Straight JointsA straight joint is used when a direct-buried cableis repaired because of a fault or dig-in. For cableinstalled in conduit, faulted cable usually is

10replaced with new cable, and joints are used inpulling vaults to join sequential runs of cable induct. Sometimes a straight joint is used when thelength of a direct buried cable run exceeds thelengths of replacement cable available. However,the use of joints for such purposes is not desirable.When a straight joint is used for repair, if there isno slack in the cable, it is sometimes necessary touse a cable stub with a joint on each end. How-ever, there are special premolded joints whichwill allow the repair of localized faults that havelimited conductor and insulation damage.

Premolded joints are preferred over otherstyles of joints because the critical voltage stresscontrol features are fabricated under controlledfactory conditions and less is left to the skill ofthe splicer and a favorable splicing environment.With premolded joints, the joint body and allother joint components are closely sized for thecable to be joined and a standard tubular com-pressed conductor connector is used.

Voltage stress control over the spliced conduc-tor is achieved by a built-in layer of conductingrubber that extends onto the cable insulation.The cable insulation shields are bridged by themolded outer shielding layer of the joint housing,which thus places this shield at ground potential.Moisture entry into the joint-cable interface isprevented by a joint housing with a tight inter-ference fit between the cable insulation and theinsulation shield and the use of a special siliconeassembly lubricant. The elastic properties of thejoint housing materials are such that a constantpressure is maintained against the cable, creatinga watertight seal. For this reason, it is mandatoryto select the joint kit that provides a tight fit.There are even cable joints available that will ac-commodate two slightly different sizes of cable.Use of such kits might reduce the need to stockan individual kit for each of the sizes of cable ona cooperative system.

A typical premolded joint is shown in Figure10.3. A one-piece housing is normally used.However, in cases of large conductor sizes andlimited available space, it may be necessary touse a joint in which the housing is made in twosections. This is less desirable than a joint with aone-piece housing because it provides an addi-tional path for water entry where the housingparts fit together.

FIGURE 10.3: Premolded Permanent Straight Joint for Primary Cables.Source: Elastimold Corporation, a division of Thomas & BettsCompany.

Cable jacket and covering over the neutral not shown.

1. Molded Insulation2. Insulation Shield3. Crimped Connector4. Conductor Shield

5. Extended Cable Entrance6. Grounding Eye7. Spliced Concentric Neutral

5 63

7

4

2 1

346 – Sect ion 10

Protective Covering Over NeutralCurrent RUS specifications require a covering (orjacket) over the cable neutral. The spliced neu-tral must also be protected from the environ-ment by one of four methods:

1. Method A—A wrap-around heat-shrinkpolymeric sleeve,

2. Method B—A tubular heat-shrinkpolymeric sleeve,

3. Method C—A tubular cold-shrinkpolymeric sleeve, and

4. Method D—A prefabricated assembly.

Heat-Shrink and Cold-Shrink Straight JointsHeat-shrink and cold-shrink permanent jointsconsist of a crimped conductor connector overwhich is placed a succession of wrapped, stress-control, and insulating layers. The heat-shrinkversion is reduced over the cable with a torch;the cold-shrink version is applied by pulling outan inner coiled expander barrier. After the con-centric neutral is spliced and taped, an overalljacket repair sleeve is shrunk down over thejoint and neutral to waterproof the joint.

This type of joint is some-times employed rather than apremolded joint. Some usersprefer this type because agiven joint kit is applicable toa wide range of conductorsizes. On the other hand, theskill and time required for

installation is greater than for the premoldedjoint, particularly for the application of the heatrequired to shrink the various components.

Premolded Permanent Wye JointsAlthough somewhat outdated and infrequentlyused, the premolded wye joint is used to con-nect a branch circuit. These type joints are verymuch permanent and, as such, have limited use-fulness because of the lack of sectionalizingflexibility and trouble-shooting opportunitiesthat a three-way connection provides. Thesejoints are constructed with an inner metallic busin the form of a wye. A typical molded wye jointis shown in Figure 10.5. The purpose of thegrounding eye is to ground the joint housing tothe neutral. The purpose of the test point is totest if the circuit is energized.

Separable Molded JointsSeparable molded straight, wye, and tee jointsare sometimes used for making temporary con-nections. Typically, separable molded joints aremade up of a series of two, three, or more “T-body” elbow terminations that use interconnect-

ing plugs to mate one T-bodyelbow to another with insulat-ing caps on the elbow ends,once assembled. These jointstypically must be assembledwith a torque wrench or spe-cial spanner wrench to tightenthe interconnection plugs.

10

FIGURE 10.4: Jacket Replacement Assembly (Method C). Source: Elastimold Corporation, a division of Thomas & BettsCompany.

STEP 1: Position Premolded Housing and Sleeves. STEP 2: Lock Premolded Housing. STEP 3: Roll Rubber Sleeves Over Cable Jacket.

Do not use separable

molded joints in

direct-buried cable

applications.


They sometimes are used to subdivide UD cir-cuits and are installed in boxes in handholes, incabinets above ground, or in vaults. If separablemolded joints are to be used for permanent ser-vice, they should be used only in non-direct-buried locations—that is, in manholes, vaults,junction boxes, switching cabinets, and so on—where they can be mounted to take all tensionand mechanical stress off the components.

Advantages and Disadvantages ofStraight Premolded and Heat- andCold-Shrink Primary JointsPremolded and heat- and cold-shrink primaryjoints have various advantages and disadvantages.

Advantages of premolded joints are as follows:

• Built-in electrical stress control, insulation,and shielding in a factory-made joint housing,

• Minimization of voids and contaminants inthe insulation,

• Factory pretesting of joint housing,• Fewer installation steps,• Shorter installation time,• Convenient circuit modifications, and• Shorter total length.

A disadvantage of premolded joints is that theyare sized to a particular cable diameter range.

Advantages of heat- and cold-shrink jointsare as follows:

• Wider range of cable diameters withone kit, and

• Smaller overall diameter.

Disadvantages of heat-shrink and cold-shrinkjoints are the following:

• Open flame hazards for heat-shrink units,• Greater skill required for installation, and• Longer length on some designs.

The selection of joint types for general use onthe cooperative system must weigh all factors in-volved in the particular situations where thejoints will be used.

ELBOWSApplicationElbows are used to terminate primary cables attransformers and switches. Elbows are also usedat junction boxes where taps and line extensionsare made to existing cable systems.

Two basic types of elbows are permitted byRUS. One type is called dead-break (formerlynon-load-break) because it must be engaged ordisengaged while the circuit is de-energized. The

10

FIGURE 10.5. Premolded Permanent Wye Joint for Primary Cables. Source: ElastimoldCorporation, a division of Thomas & Betts Company.

Spliced neutrals not shown.

1

9

763

82

5 4

1. Wye-Shaped Metallic Bus Bar2. Stress Relief Adapter3. Premolded Housing4. Crimped Conductor Connector5. Holding Collar

6. Conductor Connector Shield7. Molded Shielding Insert8. Grounding Eye9. Test Point

348 – Sect ion 10

second type, which can be engaged or disengagedfrom an energized circuit, is called load-break byvirtue of built-in arc-quenching elements.

Dead-Break ElbowsDead-break elbows can be used for 200- and600-ampere systems. RUS, however, does not ap-prove 200-ampere dead-break elbows, but doesapprove 600-ampere dead-break elbows. As witha molded joint, the end of the cable must beprepared for insertion into the elbow. The elbowcontains a conductor-shielding layer, insulation,and an insulation-shielding layer. A special con-nector is crimped onto the conductor; this con-nector fits to a contact inside the elbow. A typicaldead-break elbow is shown in Figure 10.6.

Elbows with a test point are often used to en-able the operator to determine if the circuit isenergized. The elbows also have a groundingeye for grounding the housing. They contain abuilt-in voltage relief stress cone that fits tightlyover the insulation, thus reducing the voltagestress at the end of the cable insulation shield.Manufacturers’ instructions must be followedcarefully when preparing the cable for insertioninto the elbow.

Load-Break ElbowsLoad-break elbows are used in 200-ampere circuitsonly. For 600-ampere circuits, it is necessary touse dead-break elbows or some other means foropening the circuit. The load-break elbow con-nects the primary cable to apparatus such astransformers, switches, and junction boxes. Atypical load-break elbow is shown in Figure 10.7.

The conductor contact area contains a lockingring to prevent the elbow from being quicklydislodged when the load is interrupted. Thehousing of the elbow is constructed differentlyfrom the housing of the dead-break elbow so asto extinguish an arc during removal, thus inter-rupting the primary circuit.

Elbows at JunctionsBoth 600-ampere dead-break and 200-ampereload-break elbows are used at junctions that areused for sectionalizing, looping, tapping, andjointing. Junctions are installed in handholes,apparatus cabinets for transformers, switches,and so on, or pedestals above ground.

10

Neutral and jacket not shown. (Note: 200-ampere units are not RUS approved.)

Concentric neutral and jacket not shown.

1. Elbow Housing2. Housing Shielding3. Voltage Sress Relief4. Inner Shield Insert5. Interference Fit Between

Cable Insulation Elbow6. Grounding Eye7. Cable Entrance8. Test Point9. Hot-Stick Eye10. Conductor Connector11. Male Conductor Contact

1a. Arc Follower1b. Conductor Contact2. Elbow Housing3. Locking Ring4. Conductor Connector5. Hot-Stick Eye6. Indentification Band7. Test Point8. Voltage Sress Relief9. Cable Entrance10. Grounding Eye11. Inner Shield Insert12. Housing Shielding13. Interference Fits Between

Cable Insulation Surfaceand Insulation of Elbowand Between Adapterand Elbow Insulation

8

3

5

7

7

8

910

13

11

12

6

54

1a

1b 2 3

6

4

2

1

10

9

115

FIGURE 10.6: Dead-Break Elbow for Primary Cables. Source: ElastimoldCorporation, a division of Thomas & Betts Company.

FIGURE 10.7: Load-Break Elbow for Primary Cables. Source: ElastimoldCorporation, a division of Thomas & Betts Company.


Elbow AccessoriesTypical accessories used with 200-ampere load-break elbows are shown in Figure 10.8.

A bushing insert, mounted on the apparatus, isused between the elbow and apparatus to connectthe elbow to a transformer, switchgear, and otherdevices. A feed-through insert is used betweentwo elbows to feed a cable circuit past a piece ofapparatus; the feed-through insert is attached tothe apparatus. A parking bushing is an insulatedbushing that isolates and dead-ends a cable ter-minated in an elbow. These accessories can beused to convert a radial-feed transformer to loopfeed. Insulating caps are used for dead-ending orsealing off a bushing insert, feed-throughs, andjunctions. They will also waterseal open bushings.

PREPARATION OF CABLES FORUSE WITH ELBOWSPreparation of CableThe end of the cable to be inserted into the elbowmust be cut to a length that will allow conve-nient operation of the elbow during switching.As with all cable preparation, cleanliness is ex-tremely important during the elbow installationprocess. In addition to these general steps, fol-low the elbow manufacturers’ recommendationsfor cutback dimensions.

Sealing of Cable Jacket at Entrance to ElbowIt is recommended to seal the cable jacket to theelbow to prevent moisture entry, especially inareas of high humidity. If elbows are used un-derground, such as in handholes or manholes, itis mandatory to place a waterproof seal over thecable jacket and elbow to prevent moisture fromentering the elbow.

Two types of seals can be used: the cold-shrinkseal and the heat-shrink seal. Figure 10.9 showsa typical heat-shrink seal in place. Follow manu-facturers’ recommendations when a seal is used.

Electrical Ratings of ElbowsTable 10.1 gives the electrical ratings of elbowsfor primary cables. Production tests are performedbefore shipment. Design tests are performed bythe manufacturer in order to qualify for the ANSI/IEEE Standard 386 rating. The current ratings of200 and 600 amperes for elbows are indicated inTable 10.1.

10

FIGURE 10.8: Typical 200-Ampere Elbow Accessories. Source:Elastimold Corporation, a division of Thomas & Betts Company.

FIGURE 10.9: Heat-Shrink Jacket Seal at Elbow. Source: RaychemCorporation.

Junction Feed-Through Insert

Feed-ThroughBushing Insert

Bushing Insert

Bushing Well

Parking Bushing

Insulating Cap

GroundingElbow

Load-BreakTypeElbow

Retaining Clip

Sealing Tube

Solderless GroundClamp Accessory

Sealant

350 – Sect ion 10

Elbow ConnectorsAn elbow connector is an elbow in the form ofa tee for use on dead-break 200- and 600-am-pere circuits. Elbow connectors can be used fortaps and joints to sectionalize, loop, tap, andjoin cables. Modular arrangements are usedmainly in pedestals or in apparatus cabinets andhandholes.

CABLE TERMINATIONSPrimary cable terminations are devices used tomake the transition from air-insulated conductorsystems, such as overhead lines, to solid-dielec-tric insulation systems, such as an undergrounddistribution system. The termination controls the

electrical stress at the end of the primary cableand seals the cable end from water entry. Termi-nations are, thus, used to connect primary cablesto overhead lines, switchgear, or other equipmentthat is air-insulated.

Terminations for primary cables incorporate astress cone to control the voltage stress at theend of the cable insulation shield. They also aredesigned to prevent water entry into the cableand, on some types of terminations, to providemechanical support for the cable.

Types of TerminationsRUS specifications permit the following types ofcable terminations:

10200-Ampere Elbows 600-Ampere Elbows

Voltage Class 15 kV 25 kV 35 kV 15 kV 25 kV 35 kV

(A) Production Tests(a) Minimum Corona Level, kV, rms 11 19 26 11 19 26(b) AC Withstand, 1 min., kV 34 40 50 34 40 50(c) Test Point Voltage * * * * * *

(B) Design Tests(a) Continuous Current Operation 200** 200** 200** 600** 600** 600**(b) Short Time Current, 0.17 sec., 10 10 10 25 25 25

Amperes x 1,000(c) 8-Hour Overload Current, 300 300 300 900 900 900

Amperes(d) Switching Current *** *** *** *** *** ***(e) Fault Closure **** **** **** **** **** ****(f) DC Withstand, 15 min., kV 53 78 103 53 78 103

* A test voltage is applied to the conductor system of the elbow. The response of a suitable sensing device on the elbowtest point shall indicate an energized condition.

** The ratings are for the following service conditions:• In air, including exposure to direct sunlight,• Buried in earth,• Intermittently or continuously submerged in water at a depth not exceeding six feet,• Environmental temperature of

–40°F to +140°F (for dead-break elbows) –4°F to +149°F (for load-break elbows), and

• Altitude not exceeding 6,000 feet.

*** Applicable to 200-ampere load-break elbows only: The elbow will withstand 10 complete switching operations atrated voltage and rated current without arcing to ground or impairment of its ability to meet other requirements ofthe specification.

**** Applicable to 200-ampere load-break elbows only: The test is to verify that the elbow is capable of closing on theshort time currents of (B)(b) above after the switching current test.

TABLE 10.1: Electrical Rating of Elbows. Source: ANSI/IEEE Standard 386.


• Premolded,• Porcelain,• Heat shrink, and• Cold shrink.

PremoldedThe type of cable termination shown in Figure10.10 is a premolded slip-on stress cone for in-door use. For outdoor use, because of airbornecontamination and wet conditions, the creepagepath between the conductor and ground must beincreased. This is accomplished with integral orseparately stacked premolded skirts as shown inFigures 10.11 and 10.12. Terminations designed

for outdoor use are sometimes employed in-doors where the environment is not clean. Out-door terminals also contain a seal at the end ofthe conductor to prevent moisture entry.

PorcelainA typical porcelain terminal for outdoor use isshown in Figure 10.13. These terminals incor-porate an inner molded rubber stress cone. Theouter surface of porcelain terminations are easierto clean and have higher tracking resistance. Forlocations with heavy airborne pollution and wetconditions, this type is preferred.

10

FIGURE 10.10: Premolded IndoorTermination (Slip-on Stress Cone) forPrimary Cables. Source: ElastimoldCorporation, a division of Thomas& Betts Company.

FIGURE 10.11: Premolded IntegralIndoor/Outdoor Termination forPrimary Cables. Source: ElastimoldCorporation, a division of Thomas& Betts Company.

FIGURE 10.12: Premolded ModularIndoor/Outdoor Termination withSeparate Skirts for Primary Cables.Source: Elastimold Corporation, adivision of Thomas & Betts Company.

Concentric neutral and jacket not shown. Concentric neutral and jacket not shown. Concentric neutral and jacket not shown.

1

1

2

4

66

2

1

3

4

5

3

5

7

8

3

7

2

4

5

6

1. Cable Insulation2. Interference Fit3. Stress Cone Insulation4. Stress Relief Shielding5. Internal Step for Correct Positioning6. Grounding Eye

1. Contact Connector2. Molded Rubber Cap Water Seal3. Retainer Washer4. Insulator5. Cable Insulation6. Interference Fit Between Cable

Insulation and Insulator7. Stress Relief Shielding8. Ground Connection

1. Contact Connector2. Molded Rubber Cap Water Seal3. Premolded Rubber Skirts4. Cable Insulation5. Ground Connection Clamp6. Grounding Eye7. Stress Cone

352 – Sect ion 10

Cold Shrink and Heat ShrinkFigure 10.14 shows a typical cold-shrinkterminal. A heat-shrink termination is similarin construction except that some componentsare wrapped on and others heat shrunk.

For ease of installation, the premolded orporcelain types are preferred.

Outdoor Terminal Corrosion ProtectionAn important consideration in the constructionof outdoor terminals is the corrosion resistanceof the exposed metallic parts. Galvanic corrosionresults when two dissimilar metals are connected

in the presence of an electrolyte. In sunlight,and dissolved in moisture, pollutants producedby motor vehicles and coal-burning plants be-come corrosive acids. Airborne saltwater fromthe sea or from winter roads is also very corro-sive. In these environments, terminal hardwareis best made of silicon bronze rather than plainaluminum. Areas that are dry and have little air-borne pollution may have terminal hardwaremade of aluminum or aluminum plated with tin.

Table 10.2 gives the relative corrosion resis-tance of metal combinations for use in outdoorterminals.

10

FIGURE 10.13: Porcelain Indoor/Outdoor Terminalfor Primary Cables. Source: Joslyn ManufacturingCompany.

FIGURE 10.14: Cold-Shrink Indoor/Outdoor Termination forPrimary Cables. Source: 3M Electric Products Division.

Silicon Tape Seal

SiliconInsulator

Hi-K StressRelief Tube

Silicon GreaseSemi-Con Tape

Ground Strap AssemblyMastic Seal

Marker Tape

Corrosion-Resistant Brass Top Capand Threaded Stud Connector

Aerial Lug Flat Pad Lug

+ Or

Or

O-Ring Moisture Seal

Spring-LoadedElastomer System

Arc-ResistantPorcelain Insulator

Stress Cone

Integral Cable Ground& Moisture Seal

Corrosion-ResistantBrass TopCap withEye Bolt

Corrosion-ResistantAluminum

1. Install groundstrap assemblyand seal withmastic

2. Position termina-tor over cable

3. Remove core 4. Seal top withrubber tape


10Corrosion Exposed

Resistance Rating Aerial Cable Conductor Termination Material Aerial Connector Material

Best Copper Copper or Bronze Bronze

Very Good Copper Copper or Bronze Tinned Bronze

Very Good Aluminum Tinned Aluminum Tinned Aluminum

Good Aluminum Copper or Bronze Tinned Aluminum

Poor Copper Tinned Aluminum Tinned Aluminum

Poor Aluminum Copper or Bronze Bronze

TABLE 10.2: Relative Corrosion Resistance of Metal Combinations for Outdoor Terminations.

Joints, Elbows,and Terminationsfor 600-AmperePrimary Circuits

FIGURE 10.15: Stick-Operable, Non-LoadbreakElbow Applied to Pad-Mounted Switchgear.Source: Elastimold Corporation, a divisionof Thomas & Betts Company, 2008.

ELBOWSElbows for 600-ampere circuits are basically thesame as for 200-ampere circuits, except for physi-cal size. Most manufacturers of 200-ampere elbowscannot accept cables larger than 4/0 AWG, whichis typically the point at which 600-ampere elbowsare needed. Load-break elbows are not used on600-ampere circuits because it is not practical tointerrupt a high-current arc. These type elbowsare not currently being manufactured.

Generally, 600-ampere elbows are used onhigh-current apparatus bushings—such as largepad-mounted transformers (particularly at voltagesof 4,160/2,400 volts)—and 600-ampere sectional-izing switches. Currently, several manufacturersof 600-ampere class pad-mounted and vault-mounted sectionalizing switches offer 600-ampereload-break, group-operated disconnect switches,equipped with 600-ampere threaded-stud bush-ings to accommodate dead-break 600-ampereelbows. Protected positions out of these devicesare typically 200-ampere cables, using powerfuses, vacuum interrupters, or SF6 interrupters.As these devices typically include load-breakswitching on the 600-ampere positions, elbowsfor these positions are dead-break and must beinstalled (or removed) de-energized.

In recent years, several manufacturers have in-troduced product lines of stick-operable, dead-break 600-ampere elbows, as the use of these typeswitches and larger transformers has expanded.Initially, and in the foreseeable near future, thesestick-operable, dead-break elbows and accessories

CABLE JOINTSThe designs, types, and construction of 600-am-pere joints are similar to those of 200-amperejoints except the former are larger in physical sizebecause they accommodate larger conductors.Some manufacturers provide cable adapters al-lowing 600-ampere joints to be used on smallercables of 200-ampere circuits with the advantagethat a smaller joint inventory can be maintained.

354 – Sect ion 10

will be quite expensive, compared with thefixed dead-break counterparts. Some of thestick-operable, dead-break devices require spe-cialized tools and, quite often, specialized train-ing for safe operation. Figure 10.15 shows astyle of stick-operable, dead-break elbows, withthe noted accessories available as options.

As an alternative to the high cost of some sec-tionalizing switches, manufacturers now offer pad-mounted junction boxes that can be equippedwith multipoint, insulated 600-ampere bushingterminals where two-, three-, or four-way mod-ules can be provided to the cables together inmultiple directions. With the use of stick-opera-ble, dead-break elbows, this “junction box” be-comes a 600-ampere sectionalizing switch, at agreatly reduced cost. However, the followinglimitations and cautions must be recognizedwith this alternative:

• The additional cost of stick-operable,dead-break elbows,

• The additional stocking requirements forelbows and accessories,

• Specialized training for operating personnel,and

• Limited dead-break switching operations.

10

FIGURE 10.16: Dead-Break 600-Ampere Elbow Connector andAccessories for Primary Cables. Source: Elastimold Corporation,a division of Thomas & Betts Company.

Cable connects at bottom of elbow.

8 7 6 5

4

3

2

1

9

Accessories:

10 11 12

1. Cable Adapter2. Stress Relief3. Crimped Connector4. Grounding Eye5. Test Point6. Test Point Cap7. Inner Shield Insert8. Standard Bushing Shape9. Dead-End Plug10. Elbow Connecting Plug11. Reducing Tap Well Plug12. 200-Ampere Reducing Plug

In addition, 600-ampere cables are typicallylarger and, as a result, stiffer to handle with “op-erating” sticks. Their larger size also requires ad-ditional room to train cables and the need forextra space for slack cable.

Elbow ConnectorsElbow, or T-Body, connectors for 600-ampere cir-cuits are used in applications similar to those for200-ampere circuits. A typical elbow connector isshown in Figure 10.16. Special plugs (shown inFigure 10.16) are used to dead-end one side ofthe connector, to connect to another connectorthat terminates another circuit, and to allow theconnector to be used on a 200-ampere circuit.

Several applications of the use of 600- and 200-ampere elbows deserve noting here, as follows:

• When a 600-ampere elbow is terminated on a600-ampere apparatus bushing, the use of a600-ampere to 200-ampere load-break tap-reducing plug provides a location to (1) extenda 200-ampere cable to serve additional load,or (2) install an elbow-type, metal-oxide light-ning arrester. Using this tap-reducing plug andelbow arrestor also provides an excellentlocation to verify phasing (with the arrestersremoved) with conventional phasing sticks.

• Multiple 600-ampere elbows can be “spliced”together with a 600-ampere “connector plug”that basically couples elbow-to-elbow to forma modular joint that can be separated later. Asnoted previously, these separable (modular)joints should never be direct buried and shouldbe mounted in manholes, vaults, and so on totake all weight and mechanical stress off theelbows and connector plugs.

• Elbow “dead-end plugs” provide a test pointwhen used with certain voltage testers todetermine if a cable is indeed energized.

• Elbows provide a temporary grounding point.

Note: Most 600-ampere elbows and elbow ac-cessories use fairly large-diameter threaded studs,conductive hex nut, and single-hole compressionterminals for current-carrying capability up to thefull 600-ampere rating. This single point connec-tion’s integrity is critical to the safe and stable op-eration of the circuit. Therefore, it is imperative


that all 600-ampere devices be tightened se-curely and supported securely to guarantee fullcurrent-carrying capacity. Many of these elbows

and accessories require the use of a torquewrench and many require special installationtools and wrenches to assure proper connectivity.

10

CABLE JOINTSFor new installations of sec-ondary circuits, it is not gener-ally necessary to use joints. Insome cases, however, jointsare used when a secondarycircuit is damaged. Four basictypes of joints are in use (seeFigures 10.17 to 10.19):

• Housing assembly,• Cold shrink,• Heat shrink, and• Rubber sleeve.

The housing assembly jointis the simplest to use. It consistsof a molded housing and rub-ber end caps that are placed

on the cables before the conductor is spliced.The molded housing does not contain a voltagestress cone, as is the case for primary cables, be-cause of the low voltage stress. The function ofthe joint is to prevent water entry and corrosionof aluminum conductors.

The cold-shrink joint contains an expandedsleeve over a removable spiral core. The core isremoved, allowing the sleeve to shrink downover the spliced conductor. No heat is required.

The heat-shrink joint has an adhesive-linedsleeve that is shrunk down over the spliced con-ductor using a source of heat such as a torch.

The rubber sleeve joint is not shrunk downbut relies on an interference fit when it is slidover sealant strips that are wrapped over thecables adjacent to the ends of the conductor.

TERMINATIONS AT TRANSFORMERSRUS requires that terminations for undergroundsecondary cables at transformers be insulated intheir dead-front designs. However, stress relief atterminations is not required because the voltagestress is low. The insulation is molded ontosome terminations when they are manufactured.Cable terminations at transformers mounted inenclosures, as well as underground transformers,must be moisture-sealed and insulated. The cov-ering of the terminations serves to prevent corro-sion, especially of aluminum conductors, and isa safety measure in case of accidental contact bya worker. Hand-applied tapes to cover the bush-ings and busses of the transformer are not per-mitted by RUS.

FIGURE 10.17: Housing Assembly Joint for Secondary Cables. Source:Blackburn, Thomas & Betts Company.

FIGURE 10.18: Cold-Shrink Joint for Secondary Cables. Source: 3MElectric Products Division.

FIGURE 10.19: Heat-Shrink Joint for Secondary Cables. Source:Raychem Corporation.

Insulate underground

secondary cable

terminations at

transformers.

Joints andTerminations forSecondary Circuits

356 – Sect ion 10

There are numerous types of terminations forsecondary cables. The most popular type of ter-mination for a single line is the sealed stud ter-mination in which a sealing cap covers thebolted terminal to the transformer. An insulatedbus is used for multiple terminations; the insula-tion is supplied by a rubber boot that covers thebus and the cable terminations at the bus.

An alternative to this type is the housing andsleeve assembly type. In this case, the housingprotects the cable termination from moisture andprevents accidental personal contact. Typical ex-amples of these terminations are shown in Figures10.20, 10.21, and 10.22. All of these terminations,when carefully selected for the cable size, con-ductor composition, and bushing configurationare satisfactory in most environments.

10

FIGURE 10.20: Sealed Stud Termination for Secondary Cables. Source:Blackburn, Thomas & Betts Company.

FIGURE 10.21: Bus and Rubber Cover Termination for SecondaryCables. Source: Blackburn, Thomas & Betts Company.

FIGURE 10.22: Housing and Sleeve AssemblyTermination for Secondary Cables. Source:Blackburn, Thomas & Betts Company.

Cap for Porcelain Bushings

Threaded StudSecondary Bushing

BushingNeck

O-Rings in Sealing Cap Seal AroundBushing Neck and Connector

Transformer Bushing

Metallic Bus

Transformer Bushing

“BOOT”


1. Use factory-made joints, elbows, termina-tions, and elbow connectors in 200- and600-ampere primary circuits.

2. Use factory-made joints and terminations insecondary circuits. Taped joints and termina-tions are discouraged and are to be used onlyin an emergency, as a temporary device.

3. Avoid joints for primary circuits in new in-stallations. When required for long lines,branch circuits, and so on, premoldedjoints are preferred; those with one moldedhousing rather than a split housing aremost acceptable because of less likelihoodof water entry. Permanent joints, in whichthe conductors are joined by a crimped con-nector, are preferred over separable joints.The latter should not be buried directly inthe ground, but installed in handholes,boxes, and cabinets. Use them to connectcircuits that are likely to be changed at anearly date.

4. Use load-break elbows in 200-ampere cir-cuits; use dead-break elbows in 600-amperecircuits. The most popular use of elbows is

to terminate short lengths of cables at trans-formers within the circuit; other uses are toterminate cables at apparatuses such asswitches and junctions.

5. Use T-body elbow connectors, which areseparable devices, at apparatuses such asswitches, junction boxes, and transformersto connect branch circuits and other equip-ment such as grounding cables. They are fordead-break 600-ampere circuits only.

6. Permanently connect the ends of a primarycable run or circuit to a cable termination,which provides voltage stress relief betweenthe conductor and ground and preventsentry of moisture into the cable conductor.Premolded terminations, consisting of poly-meric materials, are the most popular type.They are subject to surface tracking, how-ever, and, in areas where contaminationfrom the environment is likely, porcelainterminations are preferred.

7. Carefully select terminations to prevent cor-rosion at the cable termination and to pro-vide good mechanical support for cables.


Cable Test ing – 359

Cable Testing11Reasons for andBenefits of CableTesting by theUser

In This Section:

Although power cables are subjected to exten-sive testing by the manufacturer to ensure highquality and suitability for the intended service,accidental damage can occur during shipment,storage, or installation. Most material tests areperformed on a sampling basis that, in somecases, allow imperfections in sections of thecable to go undetected. RUS cable specificationsare stringent and require that manufacturersconduct the tests recommended in this sectionand many more to demonstrate cable quality.Despite efforts to prevent damage during ship-ment and installation, and despite extensive test-ing by manufacturers, sometimes the installedcables contain defects that result in prematureservice failures. Many users, therefore, conducttheir own quality and acceptance tests on newcable installations.

There are numerous benefits to the coopera-tive that checks new cable quality and conducts

tests on new cable installations. The most impor-tant is improvement in service reliability. Experi-ence demonstrates that, in most cases, damageto new cable during handling and installationcauses service failures within two to three years.Failures require expensive repairs and consumercomplaints and are costly to the cooperative. Re-placement of cable often results in expensivelandscape restoration or loss of service. Whencable dimensions are outside the range of indus-try specification requirements, premolded jointsand terminals will not fit properly. They may betoo tight or too loose to apply to the cable. Thelatter may cause separation from the cable orwater entry during service and shorten cable oraccessory life, again requiring costly repairs andcreating consumer dissatisfaction. Consequently,it is important that cable dimensions and con-centricity be checked by the cooperative beforethe cable is installed.

Reasons For and Benefits of Cable Testing by the User

Primary Cable Tests by the User

Secondary Cable Tests by the User

Tests by the Cable Manufacturer


Primary CableTests by the User

TESTING OF NEW PRIMARY CABLESBecause the manufacturer is required to conductmany production and final quality assurancetests in accordance with RUS specifications, it is

likely that cables are of high quality. Therefore,it is not necessary for the user to conduct a largenumber of tests. It is recommended that the user,whether by himself or by a third-party testing

360 – Sect ion 11

facility, make at least the following tests onnewly received cables:

• Dimensional conformance, including insula-tion thickness and concentricity and cablediameters, before cable installation;

• Microscope examination for voids, contami-nants, and protrusions;

• Insulation shield strip test; and• High-voltage proof test of critical cables before

placing in service (e.g., substation circuit exits).

Additional quality assurance is achieved if acable engineer is sent to the factory to witnesstests or if the cooperative contracts with a rec-ognized consultant to perform this service. Thecooperative also is advised to conduct the hotsilicone oil test on TR-XLPE cables to check forprotrusions from shields, skips in the shields,voids in the insulation, and other irregularitieson samples of newly received cables beforeinstallation.

This sample test also can be contracted withan independent laboratory. Typically, short cablesamples (approximately two feet long) are sentto a testing laboratory for examination and test-ing conducted at low cost and with a quickturnaround.

As a general rule, it is recommended that co-operatives require tests to be performed on sam-ples from the first and last reels of orders offewer than 50,000 feet, with one extra samplefor each additional 50,000 feet of cable.

It is recommended that cooperatives notifytheir suppliers in advance that they will be sam-ple testing. Further, they should establish re-sponsibilities and procedures in case of a failure,such as the following:

“Any evidence of noncompliance with the en-closed specifications shall be justification for:

1. Further testing at manufacturer’s expense(each shipping reel),

2. Rejection of the tested reel and possibly thereels preceding and following in the manu-facturing process, and

3. Rejection of the entire order, depending on theseverity and frequency of noncompliance.”

11MEASUREMENT OF PRIMARY CABLEDIMENSIONSThe measurement of the diameters and concen-tricity of cable and of selected cable componentsis an easy, straightforward way to check key pa-rameters for compliance to RUS/ICEA specifica-tions. This check also is important to ensure thatthe cable properly fits premolded commercialjoints and terminations that are generally madeby a company other than the cable manufacturer.Cable diameters and tolerances for primary cablesare given in ICEA Specification S-94-649 and re-ferred to in RUS Bulletin 1728F-U1 cable specifi-cation. Dimensions for the most popular cablesare listed in Tables 11.1 (concentric stranding)and 11.2 (compressed stranding).

The diameter over the conductor should bemeasured with a diameter tape or other suitableinstrument readable to at least 0.001 inch (1.0 mil).When the diameter of a stranded conductor isdetermined by a micrometer or caliper, it shouldbe measured around the circumference of theconductor perpendicular to the axis of the con-ductor and on the extension of a line throughthe center of the conductor and through the cen-ter of two wires in the outer layer that are 180°apart. The average of three measurements istaken as the diameter.

The measurement of the insulation thicknessshould be made with a caliper after the extrudedconductor and semiconducting insulation shieldsare removed from the cable core. If the conduc-tor shield is bonded to the insulation, the thick-ness of the insulation can best be measured witha microscope. The average thickness of insula-tion must not be less than 220 mils for 15-kV ca-bles, 260 mils for 25-kV cables, or 345 mils for34.5-kV cables made to current RUS specifications.

The measurement of the thickness of the insu-lation shield should be measured with a microm-eter, caliper, or other suitable instrument readableto at least 0.001 inch (1.0 mil) after removing theshield from the cable.

The diameter over the insulation shield shouldbe measured with a diameter tape, micrometer,or other suitable instrument readable to at least0.001 inch (1.0 mil). The measured values shouldbe within the minimum and maximum valuescalculated in Tables 11.1 and 11.2.


11Conductor(Aluminum 15-kV Cable (220 mils) 25-kV Cable (260 mils) 35-kV Cable (345 mils)or Copper) Diameter (mils) Diameter (mils) Diameter (mils)

NominalAWG or Diameter Over Insulation Over Shielding Over Insulation Over Shielding Over Insulation Over Shieldingkcmil (in.) Min. Max. Min. Max. Min. Max. Min. Max. Min. Max. Min. Max.

2 Solid 0.258 700 790 760 890 — — — — — — — —

2 0.292 735 825 795 925 — — — — — — — —

1 Solid 0.289 735 820 795 920 805 895 865 995 — — — —

1 0.332 775 865 835 965 845 935 905 1,035 — — — —

1/0 Solid 0.325 770 855 830 955 840 930 900 1,030 1,010 1,110 1,090 1,230

1/0 0.373 815 905 875 1,005 885 980 945 1,080 1,055 1,155 1,135 1,275

2/0 0.418 865 950 925 1,050 935 1,025 995 1,125 1,105 1,200 1,185 1,320

3/0 0.470 915 1,000 975 1,100 985 1,075 1,045 1,175 1,155 1,255 1,235 1,375

4/0 0.528 970 1,060 1,030 1,160 1,040 1,135 1,120 1,255 1,210 1,310 1,290 1,430

250 0.575 1,025 1,115 1,105 1,235 1,095 1,190 1,175 1,310 1,265 1,370 1,345 1,490

350 0.681 1,135 1,220 1,215 1,340 1,205 1,295 1,285 1,415 1,375 1,475 1,455 1,595

500 0.813 1,265 1,355 1,345 1,475 1,335 1,430 1,415 1,550 1,505 1,605 1,615 1,755

600 0.893 1,355 1,445 1,435 1,565 1,425 1,520 1,505 1,640 1,595 1,695 1,705 1,845

700 0.964 1,425 1,515 1,505 1,635 1,495 1,590 1,575 1,710 1,665 1,765 1,775 1,915

750 0.998 1,460 1,550 1,540 1,670 1,530 1,625 1,640 1,775 1,700 1,800 1,810 1,950

800 1.031 1,490 1,580 1,570 1,700 1,560 1,655 1,670 1,805 1,730 1,835 1,840 1,985

900 1.094 1,555 1,645 1,665 1,795 1,625 1,720 1,735 1,870 1,795 1,895 1,905 2,045

1,000 1.152 1,610 1,705 1,720 1,855 1,680 1,775 1,790 1,925 1,850 1,955 1,960 2,105

TABLE 11.1: Dimensions for Primary Cables to ICEA Specification S-94-649-2000 with Concentric Neutral(Concentric Stranding).

362 – Sect ion 11

CALCULATION OF DIAMETERSOF PRIMARY CABLESThe allowable diameter and tolerances for 15-, 25-,and 34.5-kV RUS specification cables (Table 11.1)can be calculated as indicated in Table 11.3. Thenominal diameter over the cable insulation shieldcan be calculated by adding the appropriatenominal adder for extruded insulation shield

shown in Table 11.4 to the nominal diameterover the insulation. Calculated cable diametersfor primary cables with conductor sizes from#2 AWG through 1,000 kcmil are given inTables 11.1 and 11.2. The diameter over thecable insulation or over the insulation shieldmay be measured with a diameter tape or itmay be calculated.

11

Conductor(Aluminum 15-kV Cable (220 mils) 25-kV Cable (260 mils) 35-kV Cable (345 mils)or Copper) Diameter (mils) Diameter (mils) Diameter (mils)

NominalAWG or Diameter Over Insulation Over Shielding Over Insulation Over Shielding Over Insulation Over Shieldingkcmil (in.) Min. Max. Min. Max. Min. Max. Min. Max. Min. Max. Min. Max.

2 0.283 725 815 785 915 — — — — — — — —

1 0.322 765 855 825 955 835 925 895 1,025 — — — —

1/0 0.362 805 895 865 995 875 965 935 1,065 1,045 1,145 1,125 1,265

2/0 0.405 850 935 910 1,035 920 1,010 980 1,110 1,090 1,190 1,170 1,310

3/0 0.456 900 985 960 1,085 970 1,060 1,030 1,160 1,140 1,240 1,220 1,360

4/0 0.512 955 1,045 1,015 1,145 1,025 1,115 1,105 1,235 1,195 1,295 1,275 1,415

250 0.558 1,010 1,100 1,090 1,220 1,080 1,175 1,160 1,295 1,250 1,350 1,330 1,470

350 0.660 1,115 1,200 1,195 1,320 1,185 1,275 1,265 1,395 1,355 1,455 1,435 1,575

500 0.789 1,240 1,330 1,320 1,450 1,310 1,405 1,390 1,525 1,480 1,580 1,560 1,700

600 0.866 1,325 1,415 1,405 1,535 1,395 1,490 1,475 1,610 1,565 1,670 1,675 1,820

700 0.935 1,395 1,485 1,475 1,605 1,465 1,560 1,545 1,680 1,635 1,740 1,745 1,890

750 0.968 1,430 1,520 1,510 1,640 1,500 1,595 1,580 1,715 1,670 1,770 1,780 1,920

800 1.000 1,460 1,550 1,540 1,670 1,530 1,625 1,640 1,775 1,700 1,805 1,810 1,955

900 1.061 1,520 1,610 1,630 1,760 1,590 1,685 1,700 1,835 1,760 1,865 1,870 2,015

1,000 1.117 1,575 1,670 1,685 1,820 1,645 1,740 1,755 1,890 1,815 1,920 1,925 2,070

TABLE 11.2: Dimensions for Primary Cables to ICEA Specification S-94-649-2000 with Concentric Neutral.(Compressed Stranding).


11Equation 11.1

EXAMPLE 11.1: Diameter Calculation.

Dmin = C + 80 + A + 2T

where: Dmin = Minimum diameter over insulation

Conductor Size Diameters Over Insulation (mils)(AWG or kcmil) Minimum Nominal Maximum

2–4/0 C + 30 + A + 2T Add 30 Add 60

250–500 C + 40 + A + 2T Add 30 Add 60

600–1,000 C + 50 + A + 2T Add 30 Add 60

where: C = Conductor diameterThe second term (30, 40, or 50) is twice the extrudedconductor shield thickness.A = Adder (10 mils) for 25-kV cable; do not

use for 15-kV cable.T = Minimum average insulation thickness

(RUS Bulletin 1728F-U1).

1 mil = 0.001 in.

Note. If a conductive tape and a subsequent extruded shield havebeen applied over the conductor, the minimum diameter overthe insulation must be calculated by Equation 11.1.

TABLE 11.3: Cable Diameter Tolerances.

Calculated Minimum Extruded Insulation ShieldDiameter Over Insulation Adders (mils)

(inches) Minimum Nominal Maximum

0–1.000 50 100 150

1.001–1.500 70 120 170

1.501–2.000 110 160 210

Table 11.4. Adders for Extruded Insulation Shield(Mils) to Obtain Nominal Diameter Over InsulationShield of Cable.

Calculate minimum, nominal, and maximum diameter over cable insulation for 1/0 AWG concentric (Class B) strandedconductor with extruded conductor and insulation shields, 220 mils insulation thickness, with jacket, 15 kV.

C = Conductor diameter = 373 milsFor the conductor shield extruded over the conductor (see Table 11.3) = 30 milsA = 0 mils2T = Insulation Thickness (2 × 220) = 440 milsCalculated diameter over the cable insulation = 843 mils

Round up = 845 mils

Nominal diameter over insulation (add 30 mils per Table 11.3) = 875 milsMaximum diameter over insulation (add 60 mils per Table 11.3) = 905 mils

Calculate minimum, nominal, and maximum diameter over cable insulation shield.Nominal diameter over cable insulation = 875 milsMinimum adder of insulation shield (Table 11.4) = 50 milsMinimum total diameter over insulation shield = 925 mils

Nominal diameter over cable insulation = 875 milsNominal adder of insulation shield (Table 11.4) = 100 milsNominal total diameter over insulation shield = 975 mils

Nominal diameter over cable insulation = 875 milsMaximum adder of insulation shield (Table 11.4) = 150 milsMaximum total diameter over insulation shield = 1,025 mils

1 mil = 0.001 in.

364 – Sect ion 11

HOT SILICONE OIL TEST FOR XLPEAND TR-XLPE PRIMARY CABLESThis test is a quick and easy way to check forthe cleanliness of the insulation, presence ofvoids in the insulation, the smoothness of the in-terface between the insulation and the conduc-tor shield, and presence of skips in the extrudedshields. It is possible to perform this test be-cause the polyethylene insulation becomestransparent when raised to high temperature.The test is not useful for EPR cables becausethat insulation does not become transparent.

Suspend a sample of cable, approximately 10inches long, with the jacket, neutral, and insula-tion shield removed, in a clear glass containerfilled with clean silicone oil that has beenheated to about 180°C (356°F). A typical testsetup is shown in Figure 11.1. Look for contami-nants. Also look for protrusions of the conductorshield into the insulation and for skips in theconductor shield. If any are found, do not install

11the cable. Contact the cable manufacturer or acable consultant for further advice. The determi-nation of the actual size of any observed protru-sion must be done by cutting the insulation intowafers and examining them with a microscopeor an optical comparator. The description of im-perfections and their limitations as to size allow-able in RUS cable specifications are discussedfully in ICEA Specification S-94-649.

INSULATION SHIELD STRIPPINGTEST FOR PRIMARY CABLESThis test is performed to demonstrate that the in-sulation shield can be removed from the insula-tion by normal workmanship and to demonstratethat no conducting material is left on the surfaceof the insulation upon removal of the shield.

STEP 1. Use a cable sample approximately 15inches long.

STEP 2. Cut the semiconducting shield longi-tudinally and vertically down to theinsulation.

STEP 3. Make a second, similar cut at 1/2-inchseparation from the first cut.

STEP 4. Construct a suitable measuring deviceand use it to measure the tension re-quired to pull away the 1/2-inch-widestrip of insulation shield from the cable.See the arrangement in Figure 11.2.

STEP 5. Attach the measuring device by remov-ing approximately two inches of the1/2-inch strip of each end of the cableby pulling it away at a 90° angle fromthe cable.

STEP 6. Measure the pulling tension in poundsby increasing the force on the strip untilthe strip separates from the insulation ata pulling speed of approximately 1/2inch per second.

Make the test at ambient temperature, one testat each end of the cable in opposite directionsand 180° apart. The minimum allowable tension

FIGURE 11.1: Setup for Hot Silicone Oil Test.Two cable samples in a hot silicone oil bathshow the transparency of polyethylene insulation.The oil temperature is approximately 180°C(356°F).


is six pounds and the maxi-mum allowable tension is 18lb. for TR-XLPE, and threepounds minimum and 18 lb.maximum for EPR insulation.No conducting material that isnot readily removable may beleft on the insulation and theinsulation must not be dam-aged. A local job shop shouldbe able to fabricate the mea-suring device, or an outsideconsultant can advise onwhere to obtain a device orhow to construct it. The strip-ping test is an ICEA specifica-tion and, therefore, an RUSspecification test requirement;consequently, cable manufac-turers possess this measuringdevice. Further details of thistest, plus additional informa-tion related to this test, aregiven in ICEA specifications.

HIGH-VOLTAGE PROOF TESTFOR PRIMARY CABLESThe high-voltage (dc) test is an important accep-tance test made on primary cable before thecable is placed in regular service. This test isconducted with the cable joints and either tem-porary or regular terminations connected to thecable. All other devices (e.g., lighting arresters,transformers) are disconnected from the cableexcept the regular grounding devices, which re-main connected to the cable as used in service.The proof test has the advantage of indicatingthe condition of the insulation under high-volt-age stress conditions. A high-voltage proof testis recommended for large installations, for im-portant feeder cables, or where continuity of thepower is of paramount importance (e.g., substa-tion circuit exits). The proof test may not benecessary for small installations of less impor-tance when testing of every piece of cable be-comes quite time consuming. Test equipmentmanufacturers provide lightweight portable dctest equipment along with complete instructionson how to perform proof tests on cable systems.

11

Preparation for High-Voltage Proof TestThe following preparations for the high-voltageproof test for primary cables are recommended:

• Read the test equipment manufacturers’ test-ing recommendations, when available, beforeperforming this test.

• Read IEEE Standard 400 covering safetyprocedures and dc testing techniques. Seethe references for the sources of thesepublications.

• Operate the test equipment to become famil-iar with the instruments and how to interprettheir readings.

• Decide what level of test voltage to use andthe time of voltage application. The recom-mended values are given in Table 11.5. It alsois desirable to obtain the cable manufacturer’srecommendation for these test voltages.

• Keep personnel out of the area in which thetest is to be performed and the areas at bothends of the cables being tested.

FIGURE 11.2: Setup for Insulation Shield Stripping Test.Tension is measured as a 1/2-inch-wide strip of insulationshield is removed from an XLPE cable.

366 – Sect ion 11

• Erect barriers between the test area and itssurroundings and display signs warning ofhigh-voltage testing. Commercial signs areavailable for this purpose.

• Determine test values for cable terminations,joints, etc., which may have limits on testingvoltages.

• Always have at least two people present dur-ing the test.

Setup for Proof Test of Primary CablesThe following test setup is recommended whenconducting the proof test:

• When testing the cable make sure all otherequipment—such as surge protective devices,transformers, etc.—is disconnected.

• Make sure the cable terminals are clean, dry,and free of sharp points. Sharp points causecorona and flashovers that can be eliminatedby covering with commercial electrical puttysuch as 3M Scotchfil™ or clear plastic bags.Elbow terminations need to be packed ininsulated packing stands, or covered withclear plastic bags. It is desirable to conductthe test with the cable terminals installed. Ifthe test is performed before connecting theterminals, remove the insulation shield forabout 18 inches and clean the exposed insu-lation. Although it is usually not necessary, acommercial prefabricated terminal having avoltage rating at least as high as that of thecable also can be applied in accordance withthe manufacturer’s instructions.

• Check the circuit with a 500- or 1,000-voltmegohmmeter to make sure that there are noobvious problems before starting the proof test.Allow a clearance between cable ends and sur-rounding objects of at least one inch per 10 kV.

• Check the high-voltage test set by suspendingits high-voltage lead off the ground with a dryplastic cord. Turn the voltage up to the high-est value to be used during the test. Themicro-ammeter should read close to zero.

Conducting the Proof TestAfter making the proper preparations for thehigh-voltage dc proof test described above, fol-low these steps:

STEP 1. Connect the high-voltage test set to theconductor of the cable under test.

STEP 2. Switch on the test set. Raise the voltagefrom zero to the test voltage selectedfrom the applicable AEIC specificationvalue indicated in Table 11.5. Raise thevoltage slowly, so as to reach the de-sired level in one to one-and-one-halfminutes.

STEP 3. Maintain the voltage for the preselectedtime. For acceptance of new cable notyet placed in service, the AEIC specifica-tion recommended time is five minutesduring installation or 15 minutes afterinstallation. Use the time indicated inTable 11.5 or the time recommended bythe cable manufacturer. The five-minutetime of application of voltage is speci-fied during cable installation becausetemporary terminations are often usedduring the test. These terminations mayhave corona discharge or high leakagecurrents that can cause damage to thecable ends. Most cable damage causedduring shipment or installation can bedetected during the shorter five-minutetest. In addition, less space charge willbuild up in the cable during the shortertime test.

STEP 4. Reduce voltage and switch off the testset. If a flashover occurs during the test,turn the test set off immediately. A flash-over tells you that an insulation break-down has occurred, a termination hasflashed over, or the test set has failed.If external flashover occurred during

the testing, check to see if the correctvoltage was applied. Clean the cableterminations and reposition the testleads if they were too close or becameseparated from the line.If flashover occurred inside the test

set, check to be sure you supplied thecorrect voltage for the correct time. In-ternal flashovers may indicate problemswith the equipment.

STEP 5. With the test set voltmeter indicatingzero, discharge the test set to ground.Use an approved discharge stick with

11


proper resistance followed with agrounding stick to drain the charge fromthe tested cable. When the voltagedrops below about 1 kV, connect thegrounding stick to the cable terminaland keep the cable grounded for a pe-riod of time equal to four times thelength of the dc test. Draining thecharge to ground on tested cables is avital safety procedure.

If the cable withstood the voltage for therecommended time period, and if the leakagecurrent reached a steady-state condition, the in-sulation on the cable system—including thejoints and terminations—is suitable for service. Ifthe test voltage caused flashover before the endof the time period or if the test set overcurrentcircuit tripped, the insulation of the system isnot satisfactory to place in regular service. If the

11

Cable Rated Time ofVoltage φφ – φφ Application

(kV) Period of Test DC Voltage (kV) (minutes)

Insulation Thickness — 220 mils

15 During installation 60 5

15 After installation, before service 64 15

15 During first 5 service years 52 5

15 After 5 service years 32 5











TABLE 11.5: DC Proof-Test Voltages (Conductor to Ground) for Primary Cables.

leakage current continued to gradually increasein any step of the test, lengthen the time of thatstep until it can be determined the leakage cur-rent will stabilize.

It may be necessary to remove the cable ter-minations and repeat the high-voltage proof testto determine if the cable under test, rather thanthe terminations, has failed. If it is desired to re-pair the cable and if the exact location of the fail-ure is not known, use fault location equipmentto locate the fault. Most high-dc-voltage prooftesters contain a fault-locating device (thumper)that may be used to pinpoint the exact locationof a cable fault. When this thumping equipmentis used, the fault is found by listening for athumping sound, at the cable failure, whilewalking along the ground above the cable. Apick-up coil and earphones can be employed tofacilitate hearing the thumping. Manufacturers ofproof test equipment and thumping equipmentprovide detailed instructions on the operation oftheir equipment and its use to locate cable faults.Obtain these instructions and follow them whenlocating cable faults.

HIGH-VOLTAGE STEP TEST FOR PRIMARY CABLESThe step-voltage test is a variation of the prooftest, and the same preparations and proceduresas with the proof test are used. The step-voltagetest is particularly applicable to cable circuits be-cause if the cable, joint, or termination has an in-cipient fault, a flashover will occur at a voltagebelow the failure point. This will reduce the like-lihood of damaging good cable.

When the step voltage is used, it is desirableto use voltage steps of the same magnitude, di-vided in equal times between zero and the maxi-mum test voltage level. For example, a 15-minutetest involves five three-minute steps increased inequal amounts at each step. As the cable cur -rent at each higher voltage increases, and thendecreases to a steady value in less than oneminute, this will allow time to read the current(or to show unreadably low values). The test setmicroammeter should be readable to 0.1 mi-croampere. At each step, the current for satisfac-tory cable should be steady and should berecorded. If, at any step, the current begins to

368 – Sect ion 11

increase rapidly, this indicates impending failureon the cable system. The test set should beturned off and left off for a period of time equal

11to four times the length of the dc test to groundthe system.

A high and/or unstable leakage current ismost likely due to contamination on the termina-tions, too small a clearance between energizedand grounded components, or a defect in thetest equipment. Check and reclean the termina-tions, recheck all clearances, and perform a leak-age current test on the dc equipment by raisingthe voltage with the output open circuited. Afterperforming these steps, repeat the step test onthe cable system. If high or unstable leakagecurrent is still observed, the problem is probablywith the cable system and the proof test voltagemust be applied for the required time to deter-mine the location of the defect.

TYPICAL EQUIPMENT FOR HIGH-VOLTAGE DC TESTSThe portable, high-voltage dc test set for con-ducting the proof and step-voltage tests shouldhave the maximum test voltage (usually negativepolarity), a means of increasing the voltage con-tinuously or in small steps, satisfactory outputvoltage stability, the output voltage filtered toprovide pure dc voltage, and 0.1 microampereresolution. Commercial test equipment usuallycomplies with these requirements. A typicalcommercial test set is shown in Figure 11.3.

A discharge resistor used to discharge thecable after test should have a resistance of notless than 10,000 ohms per kV of test voltage.Commercial discharge resistors are designed towithstand the full test voltage without flashoversand to withstand the discharge energy withoutoverheating. They have an insulating hook stickand a flexible conductor to connect the resistoracross the cable terminal and ground. A typicalcommercial discharge and grounding stick isshown in Figure 11.3.

PROOF TEST PRECAUTIONS WHEN SPLICINGTO SERVICE AGED CABLESWhen new primary cable is spliced to existingservice-aged PE, TR-XLPE, or EPR cables, specialprecautions must be observed when conductinga high-voltage dc proof test. The existing in-ser-FIGURE 11.3: Typical High-Voltage DC Test Set with Cable Grounding

Probe.


vice cables most likely contain water trees in theinsulation as a result of moisture penetration fromthe environment. The jacket slows, but does noteliminate, this penetration. Water trees lower thebreakdown voltage of the cable. In severe casesof water treeing, the dc test voltage may be highenough to further damage adjacent cable andcause it to fail in service prematurely. This pre-caution need not be taken when splicing topaper-oil insulated cable as this type of cable isnot damaged by dc testing.

This characteristic of PE, TR-XLPE, and EPR isrecognized by the ICEA specifications and is re-flected in the recommended dc test voltages. In

Table 11.5 note that the recommended dc testvoltages are reduced during the first five years ofservice. They are further reduced when the cablehas been in service for more than five years. It ishighly recommended that the reduced values beused if the dc tests are performed.

The above precautions apply to all mainte-nance testing of PE, TR-XLPE, and EPR cable,both jacketed and unjacketed. It should be notedthat RUS-specification cables have thicker insula-tion than do ICEA-specification cables. The thickerinsulation retards but does not eliminate watertree formation. Therefore, the lower test levelsgiven in Table 11.5 should be used.

11

Secondary Cable Tests by the User

TESTING OF NEW SECONDARY CABLESAs for primary cables, the manufacturer is re-quired to conduct many production and qualityassurance tests on secondary cables. Because600-volt cables operate at a low voltage stress,they are much less likely to fail (from electricalstress) in service than are primary cables. Conse-quently, the cooperative is advised to make onlythe following tests on newly received cables be-fore installation:

• Insulation thickness, and• Concentricity of insulation.

Some users conduct a high-voltage proof testof installed secondary cable before placing thecable in service. This practice is not recom-mended unless it is believed that the cable wasdamaged during installation.

Standard XLPE Ruggedized XLPE Conductor Size 1 Layer Average (mils)* 2 Layer Average (mils)*

4–2 AWG 60 60

1–4/0 AWG 80 80

225–500 kcmil 95 95

*The minimum thickness will not be less than 90% of the average.

TABLE 11.6: Insulation Thickness of Secondary Cables.

MEASUREMENT OF SECONDARY CABLE DIMENSIONSThe most important test for secondary cables be-fore installation is the measurement of the insu-lation thickness. The insulation thickness shouldbe in accordance with RUS Specification for 600-Volt Underground Power Cable (RUS Bulletin1728F-U2) and is given in Table 11.6 for the applicable conductor size.

The thickness of the insulation (or compositeinsulation) should be measured with a caliper,steel ruler, or micrometer. The average thicknessmust be taken as one-half of the difference be-tween the mean of the maximum and minimumdiameters over the insulation (or composite insu-lation) at one point and the average diameterover the conductor or any separator measured atthe same point. The minimum of the insulation(or composite insulation) must be taken as thedifference between (1) a measurement madeover the conductor or any separator plus thethinnest insulation (or composite insulation)wall, and (2) the diameter over the conductor orany separator. The first measurement must bemade after slicing off the opposite side of the in-sulation (or composite insulation). The thicknessof any separator between the conductor and thecovering must not be included in the thicknessof the insulation.

370 – Sect ion 11

PROOF TEST OF SECONDARY CABLESIt is not customary or generally necessary for acooperative to proof-test underground secondarypower cable that complies with RUS specifica-tions, including those that also are marked ascomplying with the Underwriters LaboratoriesType USE cable, before placing it in service. Ifthere is reason to believe that the cable has beendamaged during installation, an insulation testercan be used to check the cable. It is best to con-duct the test when the ground or conduit is wetbecause there is no integral ground plane aswith a primary cable. If the cable complies withthe requirements of Table 11.6, it is not likelythat a failure will occur when the proof test isperformed unless substantial damage occursduring handling or installation.

In a proof test, the cable should be removedfrom the circuit. It is not necessary to disconnectjoints and terminals from the cable. The voltageshould be about 3,000 volts ac applied for oneminute after being increased from zero over aperiod of 60 seconds. AEIC specifications do notcover 600-volt power cable as is the case with

primary cables. ICEA and Underwriters Labora-tories specifications do not suggest voltage testsafter installation for secondary cables.

The proof-test equipment used for this test isgenerally a portable insulation tester (Hipot) testset. A 1,000-volt megohmmeter also may beused for this test. In this case, satisfactory cableshould have an insulation resistance not lessthan one megohm. Equipment manufacturers’instructions also should be followed when mak-ing a proof test or an insulation resistance test.

INSULATION RESISTANCE TEST OF SECONDARY CABLESSome users routinely measure the insulation re-sistance of new cable before placing it in ser-vice. This test is not advised for primary cablesbecause many factors influence the IR readingand results are meaningful in only a few cases.For secondary cables, the measurement of insu-lation resistance is useful, as indicated previ-ously, as a means of determining whether cablehas been severely damaged during installation.

11

Tests by the Cable Manufacturer

Various types of tests are performed by the man-ufacturer when it is making primary cables tocomply with RUS specifications. The manufac-turer is required to continually conduct manyelectrical and physical tests on TR-XLPE and EPR insulated cables. The testing may be sepa-rated into two categories: qualification tests andproduction tests on samples and on a full reel of cable.

MANUFACTURER QUALIFICATION TESTS ON PRIMARY CABLESThese tests are intended to demonstrate the capa-bility of the manufacturer to furnish high-qualitycable with the performance characteristics suit-able for RUS member systems. Before the manu-facturer and the cable design is accepted byRUS, certified test data on a particular designmust be submitted to RUS showing compliancewith the RUS specifications, which include ap-plicable requirements of ICEA Specifications S-94-649. If requested by the purchaser, themanufacturer is required to furnish a certified

copy of the qualification test data of the cablebeing purchased.

If a manufacturer changes the insulation or thesemiconducting conductor or insulation shields,that cable with the new components must alsobe qualified to RUS specification. Each combina-tion of overall jacket material, jacket applicationmethod, concentric neutral design, insulationshield type, insulation type, and conductor sizerange must be subjected to selected qualificationtests to prove adequate performance before ac-ceptance by RUS. The qualification tests ensurethat the cable design represents a high-quality,state-of-the-art product.

MANUFACTURER PRODUCTION TESTS ON PRIMARY CABLESThese tests are conducted on a sampling basisduring production to ensure that cable perfor-mance is equivalent to that of the cable that re-ceived qualification approval, to ensure compli-ance with the applicable ICEA specification, andto detect any manufacturing defects. Numerous


tests on the insulation, the semiconducting shields,and mechanical properties of the cables are con-ducted during cable fabrication to ensure quality.Partial discharge and voltage withstand tests areconducted on full reel lengths of completed ca-bles. The requirements for the voltage withstandtests are given in Table 11.7. The dc voltage testvalues are higher than those recommended inTable 11.5 for testing installed new cables.

MANUFACTURER PRODUCTION TESTS ON SECONDARY CABLESThe cable manufacturer is required by RUS tocontinually conduct tests on 600-volt XLPE andruggedized composite XLPE-insulated cables.These tests are fewer and less stringent thanthose required by RUS for primary cables. Thetesting may be separated into three categories:

11

Cable Rated Minimum Nominal Voltage φφ – φφ Insulation 5-Minute AC Test 15-Minute DC Test

(kV) Thickness (mils) Voltage (kV)* Voltage (kV)*

15 220 44 80

25 260 52* 95*

35 345 69 125

35 420 84 155

*Withstand voltages are based on insulation thickness.

TABLE 11.7: Manufacturers’ Voltage Withstand Tests on CompletedCable.

1. RUS acceptance and listing of cable tests,2. Routine production tests, and3. Completed cable tests.

As part of the RUS acceptance and listing ofcable, the manufacturer must include certifiedtest data demonstrating compliance with RUSSpecification for 600-Volt Underground PowerCable (RUS Bulletin 1728F-U2). The manufac-turer must conduct routine production tests re-quired by NEMA Standard WC-7/ICEA 5-66-524or ICEA P-81-570. Manufacturers’ voltage testson cable rated 600 volts are given in Table 11.8.

MANUFACTURER’S CERTIFIED TEST REPORTSThe cable user is urged to specify copies of cer-tified test reports (CTRs) for primary cables atthe time of ordering. The manufacturer will fur-nish certified copies of the qualification test re-sults representative of the cable being purchasedand of the actual production test values. Theseshould be compared with the cable specifications.

When cable is not shipped directly from themanufacturer but through a local distributor,the latter may provide typical performance testdata for the type of cable being used. These reports provide useful information in the following circumstances:

• When changes or additions are made on the cable system so that similar cable can be ordered,

• When problems arise with the performance of the cable, and

• When selecting joints and terminals for thesystem.

As with primary cables, the manufacturer mustsubmit certified test data demonstrating compli-ance with the applicable secondary cable specifi-cations. For secondary cables, these specificationsare RUS Specification for 600-Volt UndergroundPower Cable (Bulletin 1728F-U2) and ANSI/ICEAS-66-524 for TR-XLPE cables and ICEA P-81-570.

Conductor Size AC Test DC Test AC Spark Test DC Spark Test (AWG or kcmil) Voltage (kV) Voltage (kV) Voltage (kV) Voltage (kV)

4–2 5.5 16.5 15.0 21.0

1–4/0 7.0 21.0 17.5 28.0

225–500 8.0 24.0 20.0 33.5

Note: The manufacturer is required to conduct at least one of the above voltage tests in accordance with NEMA WC-7/ICEA S-66-524 (XLPE) or ICEA P-81-570 (RuggedizedExtruded Insulation).

TABLE 11.8: Manufacturers’ Voltage Tests on Cables Rated Zer0 to 600 Volts.

372 – Sect ion 11

Cable testing should be performed to ensureconformance to specifications before installationand to ensure that the cable was not damagedduring installation.

1. Conduct dimensional conformance, hot sili-cone oil, and insulation stripping tests be-fore installation to identify defects that causeearly failures.

2. Conduct a high-voltage dc acceptance testwhen installing a large quantity of the sametype of cable at a given site or importantfeeder cables, or when continuity of thepower supply is of paramount importance.Contract with an outside laboratory or usein-house equipment to conduct the hot sili-cone oil and the insulation shield strippingtests. Apparatus for the latter test may bepurchased on the outside.

3. Use a diameter tape, caliper, or micrometeror equivalent device that can measure to0.001 inch (1.0 mil) to measure dimensionalconformance.

4. Use commercial high-voltage dc test equipment.

Manufacturers’ tests ensure a high-qualityproduct at the time of cable shipment. They also show that the cable design and materialshave the capability of operating satisfactorily inservice. Cable specifications ensure that themanufacturer fabricates the cable to be suitablefor use with standard joints and terminationsand complies with the cooperative’s order forthe cable.

Cable specifications provide a means to docu-ment test results in the form of a written andcertified test report.

• Cooperatives that do not have the capabilityor equipment to conduct cable tests shouldmake arrangements for an outside testingfacility.

• In all cases, the manufacturer’s certified testreports (CTRs) must be obtained.


Calculat ions for Rel iabi l i ty Studies – 373

Calculations forReliability StudiesA

Reliability Index

In This Appendix:

The reliability index that is probably quotedmost often in the literature is the average serviceavailability index (ASAI). This index is definedas the ratio of total consumer-hours of availableservice to total consumer-hours demanded. Froma particular consumer’s point of view, this indexcould be viewed as the ratio of total hours ofavailable service per year to the number 8,760,which is the total number of hours in a year.

Simple mathematical formulas relate the ASAIindex to the total hours interrupted per year.The total-hours index is also called the SystemAverage Interruption Duration Index (SAIDI).The formulas relating ASAI and SAIDI areshown in Equation A.1.

Reliability Index

Acceptability Criteria

Calculation of Reliability

Importance of Sectionalizing

Equation A.1

SAIDI = 8,760 × (1 – ASAI)

ASAI =8,760 – SAIDI

8,760

For a sample application of Equation A.1, as-sume a feeder has experienced outage timesamounting to 3.5 consumer-hours per consumerper year (SAIDI). The corresponding ASAI figureis as follows:

ASAI =8,760 – 3.5

8,760

SAIDI = 8,760 × (1 – 0.9996) = 3.5

The ASAI number is interpreted to mean thata typical consumer served from the feeder canexpect electric service to be present 99.96 per-cent of the time. The second part of EquationA.1 can be used to calculate the SAIDI from theASAI:

The total-hours index (SAIDI) will be used in thisanalysis because it is less abstract than the ASAI.

= 0.9996

374 – Appendix A

Acceptable reliability criteria are defined in RUSBulletin 161-1. Table A.1 summarizes the guide-lines of that bulletin.

AAlthough cooperatives are traditionally associ-

ated with rural areas, UD systems installed bycooperatives are likely to be in or near urbanareas. It is thus reasonable to design UD systemsto meet the acceptable outage time criterion ofone hour per year. Furthermore, the RUS guide-lines represent the total outage time to an indi-vidual consumer and include the outage time ofthe overhead system supplying the UD system.Therefore, the design outage time of the UD sys-tem itself should be much less than one hourper year.

AcceptabilityCriteria

Type of Area Maximum Acceptable Outage Hours Per Year

Urban 1.0

Rural, Near Urban Areas 2.0

Remote Rural 5.0

TABLE A.1: Acceptable Outage Hours Per Year Per Consumer.

FIGURE A.1: Components Affecting Outage Rate to the Consumer.

Calculation ofReliability

Although loop-feed UD designs are recommend-ed and normally used, these designs are certainlynot equivalent to automatically transferred dual-feed designs. Transfer to the alternate feed in atypical loop-feed UD design requires human inter-vention after an outage. Consequently, the loop-feed design does nothing to reduce the frequen-cy of outages. The advantage of the loop-feed

design is in reducing the duration of cable-fail-ure outages; this is reviewed in Section 1.

Reliability analysis of a UD system is performedin the same way as for any radial distributionsystem. The critical system components deliver-ing the power are considered to be in seriesfrom a reliability point of view, which meansthat failure of any such component causes an

Overhead Line

SurgeArrester

ElbowSurgeArrester

Cable Termination

Pad-MountedTransformerElbow Terminator

SecondaryConnections

Secondary/Service Cable

Primary Cable

Primary Cable

Calculat ions for Rel iabi l i ty Studies – 375

Aoutage at the point under study. Therefore, theoutage rates associated with the individual com-ponents may be added arithmetically to deter-mine the outage rate expected for the consumer.This direct addition rule also applies to the totalhours of outage per year for the consumer ascalculated from component total outage hours.

Calculation of the expected reliability of ser-vice to a single-phase consumer on a UD systemproceeds as follows:

STEP 1. Identify the critical components. For UDsystems, these are the supply to theriser structure, the terminator at theriser, the total cable length energizedfrom the riser, the elbow terminators,any lightning arresters connected to theprimary system section, the pad-mounted

transformer, the secondary connections,and the secondary cables.

STEP 2. Determine the outage rates and restora-tion times for each component. It willnormally be necessary to pool the expe-rience of many utilities to get the largestatistical base needed to achieve accu-racy for these parameters.

STEP 3. Determine total outage hours per yearfor each component by multiplying thecomponent outage rate by the compo-nent detection and restoration time.

STEP 4. Sum the component outage rates toget the expected outage rate at theconsumer.

STEP 5. Sum the component outage hours to getthe expected total outage hours for theconsumer.

Importance ofSectionalizing

An outage at an individual point on a UD systemoccurs when an overcurrent device operates.Therefore, the calculation of reliability must en-compass all the UD cable length and other vulner-able components that will make any overcurrentdevice operate and interrupt service to the pointunder study. This collection of components thatmight fail is referred to as the total “exposure” tooutages that is associated with a particular studypoint. This situation implies that reducing the to-tal exposure will reduce the outage rate andhours of outage at a point on the system.

Limiting the cable length and other compo-nents protected by each overcurrent device re-duces exposure. Reducing exposure can beaccomplished in two ways:

1. By increasing the number of circuits used toserve an area from a supply point, and

2. By installing coordinated overcurrent devicesat several selected points on a large circuit.

The first method is more effective, but alsomore costly. The second method yields mixedeffectiveness, because consumers located farfrom the supply point do not benefit from expo-sure reductions as much as do consumers nearthe supply point.

The concept of dividing the area to be servedinto many overcurrent-device sections to im-prove reliability is known as sectionalizing. Sec-tionalizing is often the most cost-effective wayto improve reliability. However, if there are seri-ous reliability problems with critical system com-ponents, sectionalizing alone may not achieveacceptable reliability.

As an example of the effectiveness of section-alizing, consider a single-phase UD area consist-ing of four cable runs in the configurationillustrated in Figure A.2. The area is suppliedfrom the west over a 3,000-foot cable run end-ing in a junction enclosure from which three ad-ditional 3,000-foot cable runs feed north, east,and south. Each cable run, including the supplyrun, serves 20 pad-mounted transformers byfeed-through bushings. This configuration re-quires 41 elbow terminations per cable run, in-cluding the elbows in the junction enclosureand on the arrester at the last transformer.

The following outage rates might be typicalfor the primary UD components:

Cable = 0.0020 failures/kft/yearElbow = 0.0001 failures/year

376 – Appendix A

If no sectionalizing is installed on the UD sys-tem, the outage rate expected for each con-sumer on the system is calculated as shown inEquation A.2.

AThis outage rate represents the primary UD

system only. Each consumer will also be ex-posed to outages on transformers, secondaries,and the overhead primary system that suppliesthe UD area.

The consumer outage rate caused by UD pri-mary facilities can be reduced by using a sec-tionalizing enclosure instead of a junction enclo-sure at the center of the UD system. The section-alizing enclosure will provide fuse protection forthe cable runs to the north, east, and south.

With the sectionalizing devices in service, theprimary UD outage rate to consumers on thewest cable run will become one-quarter of theprevious cable because three-quarters of the fail-ures will be cleared by sectionalizing fuses inthe central enclosure. For consumers on thenorth, east, and south cable runs, the outage ratewill be one-half the previous value. These con-sumers will be without service whenever a fail-ure occurs in their own sectionalized area or inthe supplying run from the west.

The resulting consumer outage rates from pri-mary UD failures with the sectionalizing devicesin service are as follows:

Equation A.2

FIGURE A.2: Sectionalized UD Area.

Cable Outage Rate = 12 kft × 0.0020 failures/kft/year = 0.0240 outages/year

Elbow Outage Rate = 164 elbows × 0.0001 failures/year = 0.0164 outages/year

Outage Rate for Each Consumer = 0.0240 + 0.0164 = 0.0404 outages/year

OpenPoint

20 Transformers

SectionalizingEnclosure

OpenPoint 20 Transformers

OpenPoint

20 TransformersRiser

20 TransformersWest Cable Area 0.0101 outages/year

North, East, or 0.0202 outages/yearSouth Cable Area

The outage rate is 0.0404 per year for all con-sumers without the sectionalizing cabinet.

N

Transformer and Secondary Voltage Drop – 377

Transformer andSecondary Voltage DropB

In This Appendix:

Secondary voltage drop consists of two compo-nents:

1. The transformer voltage drop, and2. The secondary and service voltage drop to

the point of delivery.

The total drop allowed in RUS Bulletin 169-4is four volts on a 120-volt base, or 3.33 percent(see Table B.1). Closer to the substation, a maxi-mum of six volts (five percent) of combineddrop is allowed. This threshold recognizes thatthe full eight-volt drop allowed on the primarysystem probably will not occur at locations closeto the substation. However, the engineer needs

Voltage Flicker

to ensure that voltage level at the point of deliv-ery to the consumer are consistent with levelsoutlined in RUS Bulletin 169-4 and/or ANSIStandard C84.1.Several different types of service configura-

tions may be present at the utilization voltagelevel. The following are the most common:

• Three-phase, four-wire, wye;• Three-phase, four-wire, delta;• Three-phase, three-wire, wye or delta;• Two phases and neutral from three-phase,four-wire, wye system;

• Single-phase, three-wire; and• Single-phase, two-wire.

To further complicate the situation, all but thelast listed above may be subject to unbalancedload conditions. Each type of service, along withthe extent of load unbalance for each, creates aunique situation requiring customized techniquesfor calculating voltage drop.In many cases, the engineer can overcome the

complications involved with the many configura-tions by identifying a worst-case single-phasesituation that is embedded in a multiphase situa-tion. An engineer who is skilled in both single-phase and balanced three-phase voltage dropcalculations can, thus, usually find the worst-case voltage drop involved in a complicated,unbalanced situation.

Maximum PercentageDrop (Volts) Drop

Substation regulated bus (output) to last distribution 8 6.67transformer (primary)

Distribution transformer (primary) to service delivery 4 3.33connection to consumer’s wiring (meter or entranceswitch)

Utility service delivery point (meter or entranceswitch) to consumer’s utilization terminal (outlet):• Loads including lighting 4 3.33• Loads without lighting 6 5.00

TABLE B.1: Allowable Voltage Drop on a 120-Volt Base.

378 – Appendix B

The simplest service voltage drop problem isalso the most common: single-phase, 240-volt,three-wire service, with the load balanced be-tween the two 120-volt legs. It is reasonable toassume a balanced load on this type of serviceas the larger appliances are almost always con-nected line to line. The balanced 120-volt loadcancels out the neutral current, so the only im-pedances that need to be considered are thetransformer impedance and the ungrounded

Bconductor impedance on one leg. This proce-dure will permit direct calculation of voltagedrop on a 120-volt base.The same calculating procedure used for one

leg of a balanced single-phase 120/240-volt sys-tem can be used for one phase of a balanced208/120-volt, three-phase, four-wire, wye system.As 208/120-volt services are also very common,skill in performing the basic single-phase voltagedrop calculation is a valuable tool for an engineer.Voltage drop on a purely resistive circuit serv-

ing a 100 percent power factor load is very sim-ple to calculate from Ohm’s law, as shown inEquation B.1.In actual cases, however, the supply circuit is

not purely resistive and the load is somewhatless than 100 percent power factor. This combi-nation of both the circuit and the load currenthaving an inductive component produces a vec-tor load current interacting with a supply circuitimpedance, itself a vector quantity. Their prod-uct, IZ, is also a vector quantity that will besomewhat out of phase with the source voltage.The voltage drop under these circumstances isthe in-phase component of IZ.Fortunately, it is not necessary to perform an

exact calculation using complex arithmetic to geta sufficiently accurate voltage drop for UD trans-former and secondary configurations. EquationB.2 produces a very close approximation to thevoltage drop for virtually all situations.The components of current needed for Equa-

tion B.2 are determined from the load currentand load power factor by using Equation B.3.The R and X components of the supply circuit

impedance, Z, are found separately for the trans-former and the secondary/service cables. Afterthese values are found for each part of the cir-cuit, the separate R values are totaled and theseparate X values are totaled to get the R and Xvalues to use in Equation B.2.In the case of the transformer, the impedance

is given on data sheets and nameplates as “%IZ.”Equation B.4 can be used to convert this imped-ance to ohms as seen by the secondary circuit.After the transformer impedance, Z, in ohms

is found from Equation B.4, the next step is tofind the resistive component, R, of this imped-ance. An estimate of the winding losses of the

Equation B.1

For resistive circuit with 100% power factor load:VDROP = IR

where: VDROP = Voltage drop, in voltsI = Current flowing in circuit, in amperesR = Supply circuit resistance, in ohms

Equation B.2

VDROP = IDR + IQX

where: VDROP = Voltage drop, in voltsID = Real component of current, in amperesR = Supply circuit resistance, in ohmsIQ = Reactive component of current, in amperesX = Supply circuit reactance, in ohms

Equation B.3

ID = IcosθIQ = Isinθ

where: ID = Real component of current, in amperesI = Measured load current, in amperescosθ = Power factor in decimal formIQ = Reactive component of current, in amperesθ = Power angle, the arc cosine of the power factor


Btransformer is usually available from data gath-ered when purchasing transformers, and the Rvalue can be directly calculated from windinglosses by using Equation B.5.It is important that only winding losses should

be used in Equation B.5. Transformers also ex-perience core losses, but this loss componentdoes not affect the transformer R used in voltagedrop calculations.After the transformer’s Z and R are deter-

mined, the transformer reactance, X, can becalculated with Equation B.6.

Example B.1 illustrates a voltage drop calculationfor a consumer service immediately adjacent to atransformer. Consideration of secondary and ser-vice cable impedances begins after this example.

Equation B.4

where: ZT = Impedance per leg or phase of transformer, in ohmsE = Voltage of leg or phase, in volts (120 volts, in most cases)%IZ = Transformer percentage impedancekVA = Transformer kVA rating per leg or phase (one-half the rating

of single-phase transformers or one-third the rating ofthree-phase wye transformers)

ZT =E2(%IZ/100)(kVA)(1,000)

Equation B.5

EXAMPLE B.1: Transformer Voltage Drop Calculation.

where: RT = Transformer resistance, in ohmsE = Voltage of leg or phase, in volts (120 volts, in most cases)W = Transformer winding losses per leg or phase, in

watts (one-half of the winding losses of single-phasetransformers or one-third of the winding losses of three-phase transformers)

kVA = Transformer kVA rating per leg or phase

RT =E2W

(kVA ×1,000)2

Determine the transformer voltage drop for a 93-ampere load at 85% power factor served immediately adjacent to a25-kVA, 120/240-volt single-phase transformer. The transformer has 3% impedance and 280 watts of winding losses.

Equation B.6

where: XT = Transformer reactance, in ohmsZT = Transformer impedance, in ohmsRT = Transformer resistance, in ohms

XT = ZT2 – RT2

The current components are obtained from Equation B.3:

ID = I cos θ = (93)(0.85) = 79 amperesθ = arc cosine (0.85) = 31.8°IQ = I sin θ = (93)(sin 31.8°) = 49 amperes

The transformer’s Z is obtained from Equation B.4:

The transformer’s R is obtained from Equation B.5:

The transformer’s X is obtained from Equation B.6:

The values needed by Equation B.2 are now available, so that equationcan be used to calculate the voltage drop:

This drop of 2.59 volts is on a 120-volt base. Refer to Table B.1 to seethat the amount of drop is within guidelines.

ZT = = = 0.03456ΩE2(%IZ/100)(kVA)(1,000)

(120)2(0.03)12,000

RT = = = 0.01290ΩE2W

(kVA × 1,000)2(120)2(0.03)(12,000)2

XT = = = 0.03206ΩZT2 – RT2 (0.03456)2 – (0.01290)2

VDROP = IDRT + IQXT = (79)(0.01290) + (49)(0.03206) =2.59 volts

380 – Appendix B

In most actual situations, the consumer’s ser-vice entrance is not immediately adjacent to thetransformer. Therefore, it is necessary to includesecondary and service cable impedance in thevoltage drop calculation. This cable impedanceconsists of resistive (R) ohms and reactive (X)

Bohms that are respectively added to the trans-former RT and XT before Equation B.2 is used.The resistance of secondary cables can be

found from standard references. Table B.2, takenfrom the Aluminum Electrical Conductor Hand-book, is an excellent compilation. For voltage

60 Hz ac at 60°C 60 Hz ac at 75°C 60 Hz ac at 90°C

Multiconductor Multiconductor MulticonductorOne Single Cable or 2 One Single Cable or 2 One Single Cable or 2Conductor in or 3 Single Conductor in or 3 Single Conductor in or 3 Single

Class B Air, Buried, or Conductors in Air, Buried, or in Conductors in Air, Buried, or in Conductors in(AWG or dc at in Nonmetallic One Metallic dc at Nonmetallic One Metallic dc at Nonmetallic One Metallickcmil) 60°C* Conduit Conduit 75°C* Conduit Conduit 90°C* Conduit Conduit

6 0.7650 0.7650 0.7650 0.8080 0.8080 0.8080 0.8480 0.8480 0.8480

4 0.4830 0.4830 0.4830 0.5070 0.5070 0.5070 0.5330 0.5330 0.5330

3 0.3820 0.3820 0.3820 0.4020 0.4020 0.4020 0.4220 0.4220 0.4220

2 0.3030 0.3030 0.3030 0.3190 0.3190 0.3190 0.3350 0.3350 0.3350

1 0.2400 0.2400 0.2400 0.2530 0.2530 0.2530 0.2660 0.2660 0.2660

1/0 0.1910 0.1910 0.1910 0.2010 0.2010 0.2010 0.2110 0.2110 0.2110

2/0 0.1510 0.1510 0.1510 0.1590 0.1590 0.1590 0.1670 0.1670 0.1670

3/0 0.1190 0.1190 0.1200 0.1260 0.1260 0.1270 0.1320 0.1320 0.1330

4/0 0.0953 0.0954 0.0963 0.1010 0.1010 0.1020 0.1050 0.1060 0.1070

250 0.0806 0.0808 0.0822 0.0847 0.0850 0.0865 0.0890 0.0892 0.0908

300 0.0672 0.0674 0.0686 0.0706 0.0708 0.0720 0.0741 0.0744 0.0756

350 0.0575 0.0578 0.0593 0.0605 0.0608 0.0623 0.0635 0.0638 0.0654

400 0.0504 0.0507 0.0525 0.0530 0.0533 0.0552 0.0556 0.0560 0.0580

500 0.0403 0.0406 0.0428 0.0424 0.0427 0.0450 0.0445 0.0448 0.0472

600 0.0336 0.0340 0.0370 0.0353 0.0357 0.0381 0.0370 0.0374 0.0400

700 0.0288 0.0292 0.0320 0.0303 0.0307 0.0337 0.0318 0.0322 0.0353

750 0.0269 0.0273 0.0302 0.0282 0.0288 0.0317 0.0296 0.0302 0.0333

1,000 0.0201 0.0207 0.0239 0.0212 0.0218 0.0253 0.0222 0.0228 0.0265

1,250 0.0162 0.0176 0.0215 0.0169 0.0177 0.0216 0.0178 0.0186 0.0228

1,500 0.0135 0.0143 0.0184 0.0141 0.0150 0.0193 0.0148 0.0158 0.0203

1,750 0.0115 0.0124 0.0168 0.0121 0.0131 0.0177 0.0127 0.0137 0.0186

2,000 0.0101 0.0111 0.0158 0.0106 0.0117 0.0166 0.0111 0.0122 0.0173

* Calculated from ICEA resistance tables for Class B stranding and corrected for temperature.Note. The metallic conduit is assumed to be steel. If aluminum is used, the effective resistance is about the same as for single conductor in nonmetallic

conduit to 4/0 size and, for larger sizes, is in the range of 1/2% to 2% more than the resistance of the conductor in nonmetallic conduit and, hence,of little significance except in critical cases.

TABLE B.2: Resistance of Class B Concentric-Strand Aluminum Cable with Thermosetting and Thermoplastic Insulation forSecondary Distribution Voltages (to 1 kV) at Various Temperatures and Typical Conditions of Installation (Ohms per 1,000feet). Adapted from the Aluminum Electrical Conductor Handbook (1989)


drop studies, the resistance at 60°C should beused unless the conductors are being loaded tovery near their thermal limits, which is not usu-ally the case.The reactance of secondary cable is composed

of inductance and capacitance. However, the ef-fect of shunt capacitance can be ignored in sec-ondary voltage calculations because of its negligi-ble effect on the results. The inductive reactancecan be calculated with the following equationsand tables.Equation B.7 determines the inductive reac-

tance of one line conductor.The distances (assumed average effective)

for various conductor arrangements are shownin Figure B.1.Table B.3 is a table of corrections for Equa-

tion B.7. In Table B.3, the term sector refers toa single conductor in which the strands arearranged approximately as a 120° section of acircle as opposed to a round conductor. Thisconductor configuration is not usually encoun-tered in contemporary UD systems. The desig-nation single conductor refers to one of severalsingle conductors of a single circuit that lieloosely together in one conduit, not boundtogether or closely adjacent on a support. Theincrease for random lay in this instance is theresult of unequal spacing of the conductors inthe conduit.Table B.4 gives conductor diameters (r = D/2)

and outside diameters for XLPE insulation asdefined in the footnote.

BEquation B.7

FIGURE B.1: Distance for Various ConductorArrangements.

where: X = Inductive reactance to neutral of one conductor, in ohms per1,000 feet

s = Spacing between centers of conductors, in inchesr = Radius of the metal portion of the conductor, in inches,

including strand shielding, if anyf = Frequency, in Hertz (it is convenient to use 377 for 2π × 60)

X = 0.0153 + 0.1404log102πƒ1,000

sr

A

A

A A

AB

A

Equilateral Triangle s= A

Right Angle Triangle s= 1.122A

Symmetrical Flat s= 1.26A

Unequal s= 3 (A × B × C)

C

382 – Appendix B

BNonmagnetic Binder Magnetic Binder

Conductor Size Round Sector Round Sector(kcmil, up to) Multiplying Factor

250 1.000 0.975 1.149 1.230300 1.000 0.970 1.146 1.225350 1.000 0.965 1.140 1.220400 1.000 0.960 1.134 1.216500 1.000 0.950 1.122 1.203600 1.000 0.940 1.111 1.199700 1.000 0.930 1.100 1.191750 1.000 0.925 1.095 1.186

Single Conductors in Conduit Multiple Conductor Cables in ConduitNonmagnetic: Increase 20% for random lay Nonmagnetic: No correctionMagnetic: Increase 50% for magnetic effect Magnetic: Use value for round conductors with

and random lay magnetic binder

Approximate Outside Diameter of Cable Thermosetting or Thermoplastic Insulation (Inches)

Size (AWG Conductor Nonshielded Fully Shieldedor kcmil) Diameter (in.) 600 V 1 kV 5 kV** 5 kV 15 kV 25 kV 35 kV 46 kV

6 0.184 0.32 0.34 0.62 0.744 0.232 0.37 0.39 0.67 0.792 0.292 0.43 0.45 0.73 0.88 1.16 1.161 0.332 0.51 0.53 0.77 0.92 1.20 1.681/0 0.373 0.55 0.57 0.85 0.96 1.24 1.72 1.452/0 0.418 0.60 0.62 0.89 1.00 1.29 1.77 1.503/0 0.470 0.65 0.67 0.95 1.06 1.34 1.83 1.55 1.824/0 0.528 0.71 0.73 1.01 1.11 1.40 1.92 1.61 1.87250 0.575 0.79 0.81 1.08 1.20 1.44 1.96 1.65 1.92350 0.681 0.90 0.92 1.18 1.31 1.56 2.06 1.80 2.03500 0.813 1.03 1.05 1.32 1.44 1.75 2.17 1.97 2.24750 0.998 1.25 1.27 1.50 1.63 1.93 2.38 2.14 2.341,000 1.152 1.40 1.42 1.73 1.85 2.09 2.56 2.30 2.501,250 1.289 1.58 1.60 1.91 2.02 2.26 2.731,500 1.412 1.70 1.72 2.04 2.13 2.38 2.961,750 1.526 1.82 1.84 2.15 2.22 2.49 3.072,000 1.632 1.92 1.94 2.29 2.36 2.61 3.13

* For voltages through 5 kV, the diameters also apply if the neutral is ungrounded. For cables above 5 kV with ungrounded neutral or cables at 133% insulationlevel, consult manufacturer’s lists.

** The 5-kV nonshielded cable, as well as all shielded cables, has strand shielding.

The listed overall diameters of 600-volt cables are from Column 4 of Table 5 of the NEC (1981) and are fairly representative of Type THW and triple-ratedRHW/RHH/USE unjacketed cable with XLPE insulation; the values are increased by 0.02 in. for 1 kV. The values in the other columns correspond closelywith those listed in ICEA No. S-94-649-2000, when increased to allow for jackets. By omitting the jacket, sometimes a lead sheath may be includedwithout increase of diameter. These diameters do not apply to cable with metallic armor. Although the listed values are generally suitable for preliminarystudies, important calculations should be made by using the actual diameter of the selected cable.

TABLE B.4: Comparison of Conductor Diameter and Approximate Cable Outside Diameter of Typical Single, Class BConcentric-Strand Aluminum Cables. Voltages are ac line-to-line with grounded neutral* except as stated. Adaptedfrom the Aluminum Electrical Conductor Handbook (1989).

TABLE B.3: Corrections for Multiconductor Cables. Adapted from the Aluminum ElectricalConductor Handbook (1989).


Example B.2 illustrates the methods for calcu-lating secondary cable resistance and reactance.The results of Example B.2 show that the

conductor resistance (0.0808 Ω/1,000 feet) isnearly three times larger than the reactance(0.029 Ω/1,000 feet) for 250-kcmil aluminum con-ductors. For smaller conductors, the resistanceincreases by a larger factor than the reactance,so the disparity between the two is even greater.Examining Equation B.2, the basic voltage dropequation, reveals that the voltage drop dependsmore on resistance than reactance for powerfactors above 71 percent. At 71 percent powerfactor, ID (real component of current) begins tobe greater than IQ (reactive component of cur-rent). It can be concluded from these observations

that accurately estimating the conductor reac-tance is not as important as accurately estimat-ing the resistance for normal load power factors.Therefore, for most studies, the engineer may

get the conductor reactance directly from atable rather than spend time calculating thereactance from Equation B.7. Table B.5, takenfrom the Aluminum Electrical Conductor Hand-book (1989), may be used to quickly estimateconductor reactance. This table assumes ran-dom lay of conductors, so the values tabulatedneed to be divided by 1.2 if tightly boundcables are being used.Example B.3 is a continuation of Example B.1

to illustrate the combined effect of transformerand cable impedances on voltage drop.

BFind the resistance and reactance per 1,000 feet for each conductor of a 250-kcmil, three-conductor, 600-voltcable, aluminum, concentric stranded, 0.79-inch diameter in nonmagnetic conduit. The conductors are bound withtape or twisted to maintain the conductors as an equilateral triangle (triplexed). The spacing between conductorsis equal to the outside diameter of a single conductor.

Determine the resistance per 1,000 feet of each conductor. From Table B.2, the ac resistance at 60°C is as follows:

where: s = 0.79 inches

r = Diameter ÷ 2 = 0.575 ÷ 2 = 0.2875, from Table B.4

EXAMPLE B.2: Secondary Cable Resistance and Reactance.

X = 0.0153 + 0.1404log103771,000

sr

X = 0.0153 + 0.1404log10 = 0.029Ω/1,000 feet3771,000

0.790.2875

0.029 × 1.149 = 0.033Ω/1,000 feet

Calculate the reactance per 1,000 feet of each conductor. From Equation B.7:

From Table B.3, Corrections for Multiconductor Cables, no random-lay correction is necessary. If this cable was ina magnetic conduit, the correction factor would be 1.149 and the reactance would be as follows:

R= 0.0808Ω/1,000 feet

384 – Appendix B

BNonmagnetic Conduit (Aluminum) Magnetic Conduit (Steel)

Conductor Covering Thickness (Insulation + Cover) (mils) Conductor Covering Thickness (Insulation + Cover) (mils)

Wire Size(AWG

or kcmil) 60 80 95 110 125 140 150 170 190 60 80 95 110 125 140 155 170 190

6 0.0404 0.0430 0.0455 0.0505 0.0537 0.0568

4 0.0386 0.0402 0.0424 0.0475 0.0503 0.0530

2 0.0359 0.0379 0.0398 0.0449 0.0473 0.0497

1 0.0367 0.0384 0.0400 0.0415 0.0430 0.0443 0.0458 0.0480 0.0500 0.0519 0.0538 0.0554

1/0 0.0357 0.0373 0.0387 0.0402 0.0416 0.0428 0.0446 0.0466 0.0484 0.0502 0.0520 0.0535

2/0 0.0348 0.0363 0.0376 0.0389 0.0402 0.0414 0.0435 0.0453 0.0470 0.0487 0.0503 0.0517

3/0 0.0339 0.0353 0.0366 0.0378 0.0390 0.0401 0.0424 0.0442 0.0459 0.0473 0.0488 0.0501

4/0 0.0332 0.0344 0.0356 0.0367 0.0378 0.0388 0.0415 0.0431 0.0445 0.0459 0.0473 0.0486

250 0.0338 0.0349 0.0360 0.0370 0.0380 0.0390 0.0399 0.0423 0.0436 0.0450 0.0453 0.0475 0.0487 0.0499

300 0.0333 0.0342 0.0353 0.0363 0.0372 0.0381 0.0390 0.0416 0.0428 0.0441 0.0453 0.0464 0.0475 0.0482

350 0.0328 0.0337 0.0347 0.0356 0.0364 0.0373 0.0382 0.0410 0.0421 0.0433 0.0445 0.0456 0.0467 0.0477

400 0.0324 0.0333 0.0342 0.0351 0.0359 0.0367 0.0375 0.0405 0.0416 0.0427 0.0439 0.0449 0.0459 0.0469

500 0.0318 0.0326 0.0334 0.0343 0.0350 0.0358 0.0365 0.0397 0.0407 0.0418 0.0428 0.0438 0.0447 0.0457

600 0.0321 0.0329 0.0336 0.0343 0.0350 0.0357 0.0401 0.0411 0.0420 0.0429 0.0438 0.0447

700 0.0317 0.0324 0.0331 0.0338 0.0345 0.0351 0.0397 0.0405 0.0414 0.0422 0.0431 0.0439

750 0.0315 0.0322 0.0329 0.0335 0.0342 0.0349 0.0394 0.0403 0.0411 0.0419 0.0428 0.0436

The above tabular values include a 20% adjustment for random lay of single conductors in a nonmagnetic conduit and a 50% adjustment for random-lay andmagnetic effect in steel conduit. If the conductors are part of a multiconductor cable with fixed spacing, multiply the tabular values in the left-hand section by0.833. For the right-hand section in such a case, multiply the adjusted left-hand section values by the magnetic-binder adjustment factors shown in Table B.3.Thus, for a triplexed 250-kcmil cable with minimum 155-mil insulation thickness of each conductor, the reactance when in nonmagnetic conduit is 0.0380 ×0.0833 = 0.0316 ohms per 1,000 ft., and when in magnetic circuit is 0.0316 × 1.149 = 0.0363 ohms per 1,000 ft.

TABLE B.5: 60 Hz Reactance of Conductors in the Same Conduit (Ohms per 1,000 feet).Source: Aluminum Electrical Conductor Handbook (1989).


BEXAMPLE B.3: Complete Secondary Voltage Drop Calculation.

Determine the total transformer and cable voltage drop that will occur if the consumer service of Example B.1 isserved over 130 feet of AWG No. 1/0 aluminum secondary triplexed UD cable with 80-mil insulation thickness.The transformer and load current conditions are the same as given in Example B.1.

From Table B.2, the resistance of AWG No. 1/0 aluminum conductor is 0.191Ω/1,000 feet at 60°C. For theactual length of 130 feet, the resistance is as follows:

R = (0.191) = 0.02483Ω1301,000

X = = 0.00387Ω1301,000

0.03571.2

RTOT = RT + R = 0.01290 + 0.02483 = 0.03773Ω

XTOT = XT + X = 0.03206 + 0.00387 = 0.03593Ω

VTOT-DROP = IDRTOT + IQXTOT = (79)(0.03773) + (49)(0.03593) = 4.74 volts

The reactance is obtained from Table B.5, divided by 1.2 to adjust for close spacing, and prorated for the130-foot actual distance:

Next, the total of transformer and cable resistances and reactances is calculated (see Example B.1 fortransformer values):

Equation B.2 can now be used to calculate the total secondary voltage drop (see Example B.1 for thedetermination of the ID and IQ values):

Comparing this result with the guidelines of Table B.1 shows the 4.74-volt drop is excessive. However, if thelocation is fairly close to the substation, the 4.74-volt drop is acceptable because it is less than the 6-volt limitapplicable under that circumstance.

Voltage Flicker Secondary flicker usually is caused by an inrushof current into consumer equipment. This inrushis usually associated with motor starting and canbe five to six times the normal full-load-ratedamperes of the motor. Although motors are themost common cause of inrush, other electricalequipment such as welders, arc furnaces, orlarge blocks of electric heat can also cause prob-lems. The problem with the sudden current in-crease is that the secondary system (transformerand conductors) must carry this momentary cur-rent with its accompanying voltage drop. The

voltage flicker is calculated either on a 120-voltbase or as a percentage of nominal voltage. Al-lowable levels of voltage dip or flicker are verysubjective. At low levels, some voltage dips gounnoticed. At slightly higher levels, the con-sumer becomes aware of the voltage dips, butthe magnitude and frequency are tolerable.However, as the magnitude or frequency of thevoltage dip increases, the dips become annoy-ing. The word frequency used in flicker evalua-tion is a reference to how often the voltage dipsoccur, such as three per hour or four per day.

386 – Appendix B

Figure B.2 is a chart for evaluating the magni-tude of permissible voltage flicker. This chart ap-pears in RUS Bulletin 160-1 and in ANSI standards.The limits are based on expected consumer an-noyance levels, which is usually the concern.However, if the voltage dip is allowed to be-come very severe, equipment operation may beimpaired or the motor that is causing the voltagedip may not maintain sufficient terminal voltageto start.For services to individual residential consumers

in UD developments, the cooperative should tryto limit voltage flicker to the level shown in Fig-ure B.2 marked “Flicker Limits for InstallationsServing Many Consumers.” The higher flickerlevel, marked “Revised Flicker Limits for Installa-tions Serving Few Consumers,” should be ap-plied only in cases in which the cooperative hasdiscussed the flicker problems with the involvedconsumers and both parties have agreed that a

greater amount of flicker is to be tolerated tocontrol the costs of correction to a lower level.However, it is important to understand that areasexist where special problems preclude strict ad-herence to this interpretation of how the flickerguidelines are to be applied in actual cases.The impedance of the primary system ahead

of the transformer is sometimes a significantcontributor to the total voltage dip during alarge secondary current inrush. The value of thisimpedance is available from primary fault cur-rent calculations performed in conjunction withsectionalizing studies. A complete analysis ofthe issue is beyond the scope of this appendix.However, Example B.4 illustrates the method fortranslating primary impedance values to the sec-ondary. The general method for calculating themagnitude of voltage flicker is the same as pre-viously demonstrated for voltage drops causedby load current.

B

FIGURE B.2: Permissible Voltage Flicker Limits.

Revised Threshold of Objection

10

9

8

7

6

5

4

3

2

1

04 8 12

Per Day Per Hour Per Minute Per Second

1 2 5 10 20 30 1 2 5 10 20 30 1 2 5 10 20 30

10

9

8

7

6

5Volts

Change

Volts

Change

4

3

2

1

0Revised Threshold of Perception

Flicker Limits for InstallationsServing Few Consumers

Voltage Flicker Limits Revised120V Basis

Flicker Limits for InstallationsServing Many Consumers


BEXAMPLE B.4. Voltage Flicker Calculation.

The transformer and service arrangement described in Example B.3 is located where the primary system line-to-ground bolted fault current is 750 amperes. The primary line-to-neutral voltage is 7.2 kV, and the fault X/R ratio at thesample location is 1.0. Estimate the voltage dip at the service when an 18-ampere, 230-volt, air-conditioning com-pressor is starting.

The transformer and secondary cable impedances are the same as cal-culated in Example B.3. The following procedure is used to estimatethe additional impedance reflected from the primary system:

When reflected through the transformer to the secondary side, thisimpedance is reduced by the square of the transformer turns ratio:

The impedances calculated in Example B.3 are for one leg only of the120/240-volt single-phase service. The impedance, ZS, above includesboth legs and must be divided by two to put it on the 120-volt baseused in Example B.3.

A system X/R ratio of 1.0 means that the system R and X are equal,and that each is equal to Z/√2. Therefore,

The total supply resistance and reactance at the point of the service arefound by adding the reflected primary values to the previous totalsfrom Example B.3.

Because of the great variety of air-conditioning equipment that exists,it is often difficult to obtain the starting amperes and starting powerfactor for the equipment involved in a particular application. A conser-vative estimate is to use a starting current of seven times the full-loadrunning current. Starting power factors for single-phase motors alsovary widely. A reasonable estimate is 80 percent if no specific infor-mation is known. In light of these guidelines, the following values areestimated for ID and IQ for this example:

Equation B.2 can now be used to estimate the voltage dip.

The expected voltage dip of 7.21 volts on a 120-volt base is below thethreshold of objection for 10 starts per hour (see Figure B.2), and it iswithin the stated guideline for two starts per hour for installations serv-ing few consumers. However, it is substantially above the allowablelimits for residential consumers. It can be concluded that the arrange-ment is marginally acceptable if consumer agreement is obtained.

ZS = ZP = 9.62 2

= 0.01067ΩESEP

2407,200

= = 0.00534ΩZS2

0.01067Ω

2

ZP = = 9.6ΩPrimary VoltageFault Current

=7,200 volts750 amperes

= = = 0.00378ΩRS2

XS2

0.00534Ω

2

VDIP = IDR + IQX = (101)(0.04151) + (76)(0.03971) =4.19 + 3.02 = 7.21 volts

RTOT = 0.03773 + 0.00378 = 0.04151Ω

XTOT = 0.03593 + 0.00378 = 0.03971Ω

ID = (7)(18)(0.8) = 101 amperesIQ = (7)(18)(0.6) = 76 amperes

Sample Speci f icat ion UGC2 for 600-Volt Secondary Underground Power Cable – 389

Sample Specification UGC2for 600-Volt SecondaryUnderground Power CableC

Table of Contents 1. Scope2. General Specifications3. Referenced Specifications4. Conductor5. Insulation

6. Tests7. Miscellaneous8. Markings9. Multiconductor Cable Assemblies

Abbreviations ANSI American National Standards InstituteASTM American Society for Testing and MaterialsAWG American Wire GaugeHDPE High Density PolyethyleneICEA Insulated Cable Engineers Association, Inc.IEEE Institute of Electrical and Electronics Engineers, Inc.KCMIL Thousand Circular MilLDPE Low Density PolyethyleneMDPE Medium Density PolyethyleneNEMA National Electrical Manufacturers AssociationNESC National Electrical Safety CodeNRECA National Rural Electric Cooperative AssociationPE PolyethyleneREA Rural Electrification AdministrationRUS Rural Utility ServicesUSE Underground Service Entrance Cable (UL Approved)XLPE Cross-Linked Polyethylene

1. Scope This document is to provide a sample specifi-cation for 600-volt single-conductor and multi-conductor secondary underground power cable.

The NRECA Transmission and DistributionUnderground Subcommittee prepared thisSample Specification UGC2.

390 – Appendix C

a. This specification covers the construction,mechanical, and electrical requirements forsingle- and multiconductor 600-volt cableswith standard cross-linked polyethylene andruggedized composite cross-linked polyethyl-ene extruded insulations. The cables shall besuitable for use in direct-burial installation inducts, conduits, or air in wet or dry locations.

b. Cable insulation shall be cross-linked poly-ethylene or ruggedized cross-linked polyeth-ylene as specified by purchaser.

c. Conductor sizes No. 6 AWG and larger forcopper and aluminum are included.

Cd. Where provisions of Sample Specification

UGC2 conflict with the presently approvedREA Bulletin U-2 or its successor document,RUS may require conditional approval.

e. Cable insulation shall be capable ofoperating continuously in both wet and drylocations at a conductor temperature of 90°Cunder normal and 130°C under emergencyoperating conditions. The cable shall havean allowable conductor temperature of250°C under short-circuit conditions.

3. ReferencedSpecifications

a. Cable shall be in compliance, as noted, withthe latest revisions of the following industrystandards:

• ICEA S-81-570, “Standard for 600 VoltRated Cable of Ruggedized Design for Di-rect Burial Installations as Single Conduc-tors or Assemblies of Single Conductors”

• ICEA S-105-692, “Standard for 600-VoltSingle Layer Thermoset Insulated UtilityUnderground Distribution Cable”

• ASTM B 3, “Specification for Soft orAnnealed Copper Wire”

• ASTM B 8, “Specification for Concentric-Lay-Stranded Copper Conductors, Hard,Medium-Hard, or Soft”

• ASTM B 230, “Specification for Aluminum1350-H19 Wire for Electrical Purposes”

• ASTM B 231, “Specification for Concentric-Lay-Stranded Aluminum 1350 Conductors”

• ASTM B 400, “Specification for CompactRound Concentric-Lay-Stranded Aluminum1350 Conductors”

• ASTM B 496, “Specification for CompactRound Concentric-Lay-Stranded CopperConductors”

• ASTM B 609, “Specification for Aluminum1350 Round Wire, Annealed and Interme-diate Tempers, for Electrical Purposes”

• ASTM B 784, “Specification for ModifiedConcentric Lay Stranded Copper Conduc-tors for Use in Insulated Electrical Cables”

• ASTM B 786, “Specification for 19 WireCombination Unilay-Stranded Aluminum1350 Conductors for Subsequent Insulation”

• ASTM B 787, “Specification for 19 WireCombination Unilay-Stranded CopperConductors for Subsequent Insulation”

• ASTM B 800, “Specification for 8000Series Aluminum Alloy Wire for ElectricalPurposes—Annealed and IntermediateTempers”

• ASTM B 801, “Specification for Concen-tric-Lay-Stranded Conductors of 8000Series Aluminum Alloy for SubsequentCovering or Insulation”

• ASTM B 901, “Specifications for CompressedRound Stranded Aluminum ConductorsUsing Single Input Wire Construction”

• ASTM B 902, “Specifications for Com-pressed Round Stranded Copper Conduc-tors Using Single Input Wire Construction”

• ASTM D 1248, “Specification for Poly-ethylene Plastics Molding and ExtrusionMaterials”

• ASTM D 1693, “Test Method for Environ-mental Stress-Cracking of Ethylene Plastics”

b. Availability of Publications

(1) Copies of the American National Stan-dards Institute/Insulated Cable Engi-neers Association, Inc. (ANSI/ICEA),publications can be obtained fromGlobal Engineering Documents for a feeat the address indicated below:

IHS Global Engineering Documents15 Inverness Way EastEnglewood, CO 80112Telephone: 877.413.5184E Mail: [email protected] Site: global.ihs.com

2. GeneralSpecifications


C(2) Copies of American Society for Testing

and Materials (ASTM) publications refer-enced in this specification can be ob-tained from ASTM for a fee at theaddress indicated below:

ASTM100 Barr Harbor DriveWest Conshohocken, PA 19428-2959Telephone: 610.832.9585Web Site: astm.org

(3) Copies of the National Electrical Safety Code(NESC) can be obtained from IEEE for a feeat the address indicated below:

Institute of Electrical and ElectronicsEngineers, Inc. (IEEE)IEEE Service Center445 Hoes LanePiscataway, NJ 08855Telephone: 800.678.4333Web Site: shop.ieee.org/ieeestore

4. Conductor a. Conductors shall be copper or aluminumas specified by the purchaser.

b. Copper conductors shall be Class Bstranded annealed copper in accordancewith ASTM B-3 or ASTM B-8.

c. Aluminum conductors shall be one ofthe following:

(1) Solid EC grade aluminum; either soft,half-hard, or three-quarter hard in accor-dance with ASTM Specification B-230 orASTM Specification B-609.

(2) Class B stranded EC grade aluminum;either three-quarter hard or hard-drawnin accordance with ASTM SpecificationB-230 or ASTM Specification B-231, orSeries 8000 aluminum alloy in accor-dance with ASTM B 800.

(3) Compact-round stranded in accordancewith ASTM Specification B-400. Combi-nation unilay stranded aluminum phaseconductors shall conform to ASTM B 786.Combination unilay stranded Series 8000aluminum alloy conductors shall complywith ASTM B 800.

(4) Single-input-wire (SIW) stranded andcompressed in accordance with ASTM B901 and ANSI/ICEA S-105-692 andANSI/ICEA S-81-570. SIW strandedSeries 8000 aluminum alloy conductorshall comply with ASTM B 800.

d. The solid conductor and center strand ofstranded conductors shall be indented withthe manufacturer’s name and year of manu-facture at regular intervals with no more than12 inches (0.3 m) between repetitions.

5. Insulation a. Insulation shall be one of the following asspecified by the purchaser:

(1) Ruggedized Construction

Ruggedized composite cross-linkedpolyethylene insulation composedof either: (a) an inner layer of blacklow- or medium-density polyethyl-ene and an outer layer of blackhigh-density polyethylene firmlybonded together, or (b) a singlelayer of black crosslinked highdensity polyethylene.

The composite insulation shall com-ply with the physical and electricalproperties as indicated in ICEA Pub-

lication S-81-570, and the finished ca-ble shall meet the mechanical abuserequirements specified in Section 6.3.The physical, electrical, and mechan-ical abuse requirements shall betested in accordance with ICEA Pub-lication S-81-570.

The nominal composite insulationwall thickness and each layer form-ing the composite insulation wall(LDPE or MDPE inner layer andHDPE outer layer) shall have a nomi-nal thickness as shown in Table C.1.

The composite wall minimum thick-ness shall not be less than 90 percentof these values.

a. Watertight seals shall be applied to all cableends to prevent the entrance of moisture dur-ing transit or storage. Each end of the cableshall be firmly and properly secured to the reel.

b. Cable shall be placed on shipping reels suit-able for protecting it from damage duringshipment and handling. Reels shall be pro-vided with a suitable covering to help iden-tify shipping damage to the cable.

c. A durable label shall be securely attached toeach reel of cable. The label shall indicatethe purchaser’s name and address, purchaseorder number, cable description, reel num-ber, feet of cable on the reel, tare and grossweight of the reel, and beginning and end-ing sequential footage numbers.

392 – Appendix C

C

The minimum thickness shall not be lessthan 90 percent of these values.

b. If requested by the purchaser, the cable shallmeet the requirements of and labeled ascomplying with Underwriters Laboratoriesstandards for Type USE 600-volt single-conductor cable.

c. Mechanical Abuse Requirements(Ruggedized Design Only)

(1) Tests are to be performed oncompleted cable, with No. 1/0 AWGconductor, in accordance with ICEAPublication S-81-570.

Compositeor Single-Layer

Nominal Thickness of Each Layer for

Conductor Size Insulation WallComposite Insulation Construction

(AWG or kcmil) Thickness (mils) Inner Layer (mils) Outer Layer (mils)

6-2 60 30.0 30.0

1-4/0 80 40.0 40.0

*250-500 *95 *47.5 *47.5

501-1,000 110 55.0 55.0

* Or 80 mil (40/40 mil) thickness, as specified by user.

(2) Alternative: Non-RuggedizedConstruction

Standard cross-linked polyethyleneinsulation that meets the require-ments of ICEA Publication S-105-692. The nominal thickness ofinsulation shall not be less thanshown in Table C.2.

Conductor Size Insulation Wall(AWG or kcmil) Thickness (mils)

6-2 60

1-500 80

6. Tests

7. Miscellaneous

a. Qualification Tests. As part of a request forRUS consideration for acceptance and listing,the manufacturer shall submit certified testdata results to RUS that detail full compli-ance with ICEA S-81-570 for ruggedizedcable design.

(1) Test results shall confirm compliancewith each of the material tests, produc-tion sampling tests, tests on completedcable, and qualification tests includedin ICEA S-81-570.

b. Production tests shall be performed in accor-dance with ICEA S-81-570 and ICEA 692. Ifrequested by the purchaser, a certified copyof the results of all production tests performedin accordance to this section shall be furnishedon all orders. For all orders in excess of 10,000feet, the manufacturer shall furnish results ofproduction tests unless the purchaser waivesthis requirement through written instructions.

c. For Type USE cable, the manufacturer shallperform all production tests required byUnderwriters Laboratories.

d. Frequency of sample tests shall be in accor-dance with ICEA T-26-465/NEMA WC53.

TABLE C.1: Nominal Composite Insulation Layer Thickness (Ruggedized) TABLE C.2: Nominal Insulation Thickness(Non-Ruggedized)


C8. Markings

9. MulticonductorCableAssemblies

All cable provided under this specification shallhave suitable markings on the outer surface ofthe jacket at sequential intervals not exceedingtwo feet (0.61 m). The legend shall indicate thename of the manufacturer, conductor size and

material, type and thickness of insulation, volt-age rating, and year of manufacture. There shallbe no more than six inches (0.15 m) of un-marked spacing between legend sequences.

a. Cable shall be furnished in multiconductorassemblies if specified by the purchaser.Such assemblies shall consist of two (du-plex), three (triplex), or four (quadraplex)single-conductor cables which individuallymeet all requirements of this specification.

b. The cable assembly shall meet all require-ments of ICEA S-105-692 or ICEA S-81-570as applicable.

c. A reduced neutral conductor (if specified)shall be no more than two standard sizessmaller than the phase conductor and nosmaller than #2 AWG aluminum or #4 AWGcopper or, where the phase conductors aresmaller than #2 AWG aluminum or #4 AWGcopper, the neutral conductor shall be thesame size as the phase conductor.

d. A neutral conductor shall be clearly identifiedin each assembly. Neutral identification shallbe in the form of three extruded weather re-sistant yellow stripes 120° apart. Each stripeshall cover a minimum of 20 percent of theneutral outer circumference. Stripes shallalso be durable under conditions typicallyfound in direct burial installations.

(1) A solid yellow neutral insulationshall be supplied if specified bythe purchaser.

e. Multiconductor assemblies shall be furnishedwith a lay not exceeding sixty (60) times thediameter of an individual cable.

f. Only one cable within a multiconductor as-sembly shall have sequential footage markings.

Checkl ist for Information Requirements – 395

Checklist for InformationRequirementsD

Project Information Checklist

(1) Delivery is: 1φ 3φ

(2) Service voltage needed: 120/240 volts

208/120 volts, grounded wye

480/277 volts, grounded wye

240 volts, delta

480 volts, delta

Other ______________________________________________________

(3) Connected loads

Residential kW pf Diversity

Heating*

Cooling*

Water heater

Range/oven

Miscellaneous

*If available, record the locked rotor amps (LRA) of the largest compressor: LRA = __________ Amperes

Commercial kW or Hp pf Diversity

Heating

Cooling

Lighting

Base load (receptacles, small motors)

Water heater

Process machinery

Large motor loads

Size (horsepower) of largest motor started across line: _________________

Number of times started per day: _________________

396 – Appendix D

(4) Project Schedule

D

(5) Copies of Pertinent Plans

Developer/Contractor Schedule Planned Date Actual Date

Temporary power service needed

Permanent power service needed

Roadways cut

Property pins (front and back) in place and lot numbers displayed

Final grade established

Roads paved

Sidewalks and curbing installed

Start Date Completion Date

Utility Schedule Planned Actual Planned Actual

Water/sewer

Telephone

Cable television

Gas

Power

Plans Date Received

a. Subdivision Plat

b. Grading Plan

c. Utility Installation Plans

Water/sewer/surface drainage

Telephone

Cable television

Traffic control

Streetlight circuits

(6) Consumer-Owned Underground Facilities:

Water line

Sewer line

Septic tank and drain lines

Satellite dish cable

Irrigation system

Electric lines

Other ___________________________________________________________________________

Specification UGC1 – 397

Sample Specification for 15-, 25-,and 35-KV Primary UndergroundMedium Voltage Concentric NeutralCable (Specification UGC1)

ETable of Contents

Abbreviations ac Alternating CurrentANSI American National Standards InstituteASTM American Society for Testing and MaterialsAWG American Wire GaugeEPR Ethylene Propylene RubberICEA Insulated Cable Engineers Association, Inc.LDPE Low Density PolyethyleneLLDPE Linear Low Density PolyethyleneRUS U.S. Department of Agriculture Rural Development, Electric ProgramTR-XLPE Tree Retardant Cross-Linked PolyethyleneXLPE Cross-Linked Polyethylene

1. Purpose a. This document is to provide a sample speci-fication for the purchase of medium voltage15-, 25-, and 35-kV single-phase and multi-phase medium voltage underground powercable. The NRECA Transmission and Distrib-ution Underground Subcommittee prepared

this Sample Specification UGC1. The require-ments of this specification are generally con-sistent with RUS’s proposed changes to REABulletin 50-70 (U-1). When accepted, the newRUS document will be Bulletin 1728F-U1.

1. Purpose2. General Specifications3. Referenced Specifications4. Conductor5. Conductor Shield (Stress Control Layer)6. Insulation

7. Insulation Shielding8. Concentric Neutral Conductor9. Overall Outer Jacket10. Dimensional Tolerances11. Tests12. Miscellaneous

2. GeneralSpecifications

a. This specification details recommendedrequirements for 15-, 25-, and 35-kV powercables for use on 12.5/7.2-kV (15-kV rated),24.9/14.4-kV (25-kV rated), and 34.5/19.9-kV

(35-kV rated) underground distribution systemswith multigrounded neutral. Cable complyingwith this specification shall consist of a singlesolid or strand-filled conductor which is

398 – Appendix E

insulated with tree-retardant cross-linkedpolyethylene (TR-XLPE) or ethylene propy-lene rubber (EPR), with concentrically woundcopper neutral conductors covered by anonconducting or semiconducting jacket.

b. The cable may be used in singlephase andmultiphase circuits.

c. Acceptable conductor sizes are: No. 2 AWG(33.6 mm2) through 1,000 kcmil (507 mm2)for 15-kV cable, No. 1 AWG (42.4 mm2)through 1,000 kcmil (507 mm2) for 25-kV,

Eand 1/0 (53.5 mm2) through 1,000 kcmil (507mm2) for 35-kV cable.

d. Except where provisions therein conflictwith the requirements of this specification,the cable shall meet all applicable provisionsof ANSI/ICEA S-94-649.

e. Where provisions of this specification con-flict with the presently approved REA Bul-letin 50-70 (U1) or its successor document(1728F-U1), RUS may require conditionalapproval.

3. ReferencedSpecifications

a. The following specifications/standardsare considered pertinent to this samplespecification:

• ANSI/ICEA S-94-649, “Standard forConcentric Neutral Cables Rated5,000–46,000 Volts”

• ANSI/IEEE C2, “National ElectricalSafety Code”

• ICEA S-97-682, “Utility Shielded Power Ca-bles Rated 5 Through 46 kV”

• ICEA T-31-610, “Guide for Conducting aLongitudinal Water Penetration ResistanceTest for Sealed Conductor”

• ICEA T-32-645, “Guide for EstablishingCompatibility of Sealed Conductor FillerCompounds with Conductor Stress Con-trol Materials”

• ASTM B 3, “Specification for Soft orAnnealed Copper Wire”

• ASTM B 8, “Specification for Concentric-Lay-Stranded Copper Conductors, Hard,Medium-Hard, or Soft”

• ASTM B 230, “Specification for Aluminum1350-H19 Wire for Electrical Purposes”

• ASTM B 231, “Specification for Concentric-Lay-Stranded Aluminum 1350 Conductors”

• ASTM B 400, “Specification for CompactRound Concentric-Lay-Stranded Aluminum1350 Conductors”

• ASTM B 496, “Specification for CompactRound Concentric-Lay-Stranded CopperConductors”

• ASTM B 609, “Specification for Aluminum1350 Round Wire, Annealed and Interme-diate Tempers, for Electrical Purposes”

• ASTM B 786, “Specification for 19 WireCombination Unilay-Stranded Aluminum1350 Conductors for Subsequent Insulation”

• ASTM B 787, “Specification for 19 WireCombination Unilay-Stranded CopperConductors for Subsequent Insulation”

• ASTM B 835, “Specification for CompactRound Stranded Copper Conductors UsingSingle Input Wire Construction”

• ASTM B 836, “Specification for CompactRound Stranded Aluminum ConductorsUsing Single Input Wire Construction”

• ASTM B 901, “Specifications for Com-pressed Round Stranded Aluminum Conduc-tors Using Single Input Wire Construction”

• ASTM B 902, “Specifications for Com-pressed Round Stranded Copper Conduc-tors Using Single Input Wire Construction”

• ASTM D 412, “Test Methods for Vulcan-ized Rubber and Thermoplastic Rubbersand Thermoplastic Elastomers-Tension”

• ASTM D 746, “Test Method for BrittlenessTemperature of Plastics and Elastomersby Impact”

• ASTM D 1248, “Specification for Poly-ethylene Plastics Molding and ExtrusionMaterials”

• ASTM D 1693, “Test Method for Environ-mental Stress-Cracking of Ethylene Plastics”

• ASTM D 2275, “Test Method for VoltageEndurance of Solid Electrical InsulatingMaterials Subjected to Partial Discharges(Corona) on the Surface”

• ASTM D 2765, “Test Methods for Determi-nation of Gel Content and Swell Ratio ofCross-Linked Ethylene Plastics”


E• ASTM D 3349, “Test Method for Absorp-

tion Coefficient of Ethylene PolymerMaterial Pigmented with Carbon Black”

• ASTM D 4496, “Test Method for DCResistance or Conductance of ModeratelyConductive Materials”

• ASTM E 96, “Test Methods for WaterVapor Transmission of Materials”

b. Availability of Publications

(1) Copies of the American National Stan-dards Institute/Insulated Cable Engi-neers Association, Inc. (ANSI/ICEA)S-94-649 publication can be obtainedfrom IHS for a fee at the address indi-cated below:

IHS15 Inverness Way EastEnglewood, CO 80112Telephone: 303.397.7956 or 877.413.5187Fax: 303.397.2740E-Mail: [email protected] Site: global.ihs.com

(2) Copies of American Society for Testingand Materials (ASTM) publications refer-enced in this specification can be ob-tained from ASTM for a fee at theaddress indicated below:

ASTM100 Barr Harbor DriveWest Conshohocken, PA 19428-2959Telephone: 610.832.9585Web Site: astm.org

(3) Copies of the National Electrical SafetyCode (NESC) can be obtained from IEEEfor a fee at the address indicated below:

Institute of Electrical and ElectronicsEngineers, Inc. (IEEE)IEEE Service Center445 Hoes LanePiscataway, NJ 08854Telephone: 800.678.4333Web Site: shop.ieee.org/ieeestore

4. Conductor a. Central phase conductors shall be copper oraluminum as specified by the purchaserwithin the limits of section 2.c.

b. Central copper phase conductors shall beannealed copper in accordance with ASTM B3.Concentric-lay-stranded phase conductors shallconform to ASTM B 8 for Class B stranding.Compact round concentric-lay-stranded phaseconductors shall conform to ASTM B 496.Combination unilay stranded phase conductorsshall conform to ASTM B 787. If not specifiedotherwise by the purchaser, stranded phaseconductors shall be Class B compressed strand.

c. Central aluminum phase conductors shall beone of the following:

(1) Solid: Aluminum 1350, H14 or H24, H16or H26, in accordance with ASTM B 609.

(2) Stranded: Aluminum 1350, H14 or H24,H16 or H26, in accordance with ASTM B609. Concentric-lay-stranded (includescompressed) phase conductors shallconform to ASTM B 231 for Class B

stranding. Compact round concentric-lay-stranded phase conductors shall conform toASTM B 400. Combination unilay strandedaluminum phase conductors shall conformto ASTM B 786. If not specified otherwise bythe purchaser, stranded phase conductorsshall be class B compressed strand.

d. The interstices between the strands ofstranded conductors shall be filled with amaterial designed to prevent the longitu-dinal migration of water that might enterthe conductor. This material shall becompatible with the conductor and con-ductor shield materials. The outer sur-faces of the strands that form the outerlayer of the stranded conductor shall befree of the strand fill material. Compatibil-ity of the strand fill material with the con-ductor shield shall be tested and shall bein compliance with ICEA T-32-645. Waterpenetration shall be tested and shall be incompliance with ICEA T-31-610.

400 – Appendix E

e. The center strand of stranded conductorsshall be indented with the manufacturer’sname and year of manufacture at regular

Eintervals with no more than 12 inches(0.3 m) between repetitions.

6. Insulation

a. A non-conducting (for discharge-resistantEPR) or semiconducting shield (stress con-trol layer) meeting the applicable require-ments of ANSI/ICEA S-94-649 shall beextruded around the central conductor.

b. The minimum thickness at any point shall bein accordance with ANSI/ICEA S-94-649 ex-cept minimum thickness requirements shallalso be met at all points. See Table E.1.

c. The conductor shield shall have a tempera-ture rating equal to, or higher than, that ofthe insulation.

d. The void and protrusion limits on the con-ductor shield shall be in compliance withthe ANSI/ICEA S-94-649.

5. ConductorShield (StressControl Layer) Conductor Size Extruded Shield Thickness

AWG Minimum Pointor kcmil mm2 Mils mm

8–4/0 8.37–107 12 0.30

212–550 107–279 16 0.41

551–1,000 279–507 20 0.51

TABLE E.1: Extruded Conductor ShieldThickness.

a. The insulation shall conform to the require-ments of ANSI/ICEA publication S-94-649 andmay either be tree retardant cross-linked poly-ethylene (TR-XLPE) or ethylene propylenerubber (EPR), as specified by the purchaser.

b. The thickness of insulation shall be as shownin Table E.2.

c. The contamination, void, and protrusion lim-its on the insulation shall be in compliancewith the ANSI/ICEA S-94-649.

Cable Rated Voltage Nominal Thickness Minimum Thickness Maximum Thickness

15 kV 220 mils (5.59 mm) 210 mils (5.33 mm) 250 mils (6.35 mm)



7. InsulationShielding

a. A semiconducting thermosetting polymericlayer meeting the requirements of ANSI/ICEA S-94-649 shall be extruded tightly overthe insulation to serve as an electrostaticshield and protective covering. The shieldcompound shall be compatible with, but notnecessarily the same material compositionas, that of the insulation (e.g., copolymershield may be used with EPR insulation). Asemi-conducting thermoplastic layer meeting

the requirements of ANSI/ICEA S-94-649 willbe allowable on discharge-resistant EPR cable.

b. The thickness of the extruded insulationshield and the concentric neutral indent shallbe in accordance with ANSI/ICEA S-94-649.See Table E.3.

c. The shield shall be applied such that allconducting material can be easily removedwithout the need for externally applied heat.Stripping tension values shall be six through

TABLE E.2: Nominal, Minimum, and Maximum Insulation Thickness.


18 pounds (2.72 through 8.16 kg) for EPRdischarge-free cable and for TR-XLPE.Discharge-resistant cables shall have striptension value of zero through 18 pounds(zero through 8.16 kg).

d. The void and protrusion limits on the insula-tion shield shall be in compliance with theANSI/ICEA S-94-649.

E

8. ConcentricNeutralConductor

9. OverallOuter Jacket

Calculated Minimum Insulation Shield Thickness Maximum ConcentricDiameter Over the Insulation Minimum Point Maximum Point Neutral Indent

inches mm mils mm mils mm mils mm

0–1.000 0–25.40 30 0.76 60 1.52 15 0.38

1.001–1.500 25.43–38.10 40 1.02 75 1.91 15 0.38

1.501–2.000 38.13–50.80 55 1.40 90 2.29 20 0.51

2.001 and larger 50.83 and larger 55 1.40 105 2.67 20 0.51

TABLE E.3: Insulation Shield Thickness for Cables with Wire Neutral.

a. A concentric neutral conductor shall consistof annealed round, uncoated copper wiresin accordance with ASTM B 3 and shall bespirally wound over the insulation shieldwith uniform and equal spacing betweenwires. The concentric neutral wires shall re-main in continuous intimate contact with theextruded insulation shield. Full neutral is re-quired for single phase and 1/3 neutral forthree phase applications unless otherwisespecified. The minimum wire size for theconcentric neutral is 16 AWG (1.32 mm2).

b. When a flat strap neutral is specified by thepurchaser, the neutral shall consist of copperstraps applied concentrically over the insula-tion shield with uniform and equal spacingbetween straps and shall remain in intimatecontact with the underlying extruded insula-tion shield. The straps shall not have sharpedges. The thickness of the flat straps shallbe not less than 20 mils (0.5 mm).

a. An electrically nonconducting or semi-con-ducting outer jacket shall be applied directlyover the concentric neutral conductors.

(1) The jacket material shall be an extruded-to-fill jacket that fills the area betweenthe concentric neutral wires and coversthe wires to the proper thickness. Thejacket shall be free stripping. The jacketshall have three red stripes longitudi-nally extruded into the jacket surface120° apart as per ANSI/ICEA S-94-649.

(2) Nonconducting jackets shall consist oflow density, linear low density, or black

thermoplastic polyethylene (LDPE,LLDPE) compound meeting the require-ments of ANSI/ICEA S-94-649, andASTM D 1248 for Type I, Class C, Cate-gory 4 or 5, Grade J3 or Type II beforeapplication to the cable. Polyvinyl chlo-ride (PVC) or chlorinated polyethylene(CPE) jackets are not acceptable.

(3) Semi-conducting jackets shall have aradial resistivity not exceeding 100 ohm-meters and a maximum water vaportransmission rate of 2 g/m2/24 hoursat 38°C (100°F) and 96 percent relativehumidity in accordance with ASTM E 96.

402 – Appendix E

b. The minimum thickness of thejacket over metallic neutral wires orstraps shall comply with the thick-ness specified in ANSI/ICEAS-94-649. See Table E.4.

ECalculated Minimum Diameter Insulation Shield ThicknessOver the Concentric Neutral Minimum Point Maximum Pointinches mm mils mm mils mm

0–1.500 0–38.10 45 1.14 80 2.03

1.501 and larger 38.13 and larger 70 1.78 120 3.05

TABLE E.4: Extruded-to-Fill Jacket Thickness.

10. DimensionalTolerances

11. Tests

Cables conforming to this specification shallhave all dimensional tolerances meeting therequirements of ANSI/ICEA S-94-649.

a. Qualification Tests. As part of a request forRUS consideration for acceptance and listing,the manufacturer shall submit certified testdata results to RUS that detail full compli-ance with ANSI/ICEA S-94-649 for eachcable design.

(1) Test results shall confirm compliancewith each of the material tests, produc-tion sampling tests, tests on completedcable, and qualification tests included inANSI/ICEA S-94-649.

(2) The testing procedure and frequency ofeach test shall be in accordance withANSI/ICEA S-94-649.

(3) Certified test data results shall be sub-mitted to RUS for any test, which is des-ignated by ANSI/ICEA S-94-649 as being“For Engineering Information Only,” orany similar designation.

b. Partial Discharge Tests. Manufacturersshall demonstrate that their cable complieswith paragraph 11.b. (1) or 11.b. (2) ofthis specification.

(1) Each shipping length of completed cableshall be tested and have certified testdata results available indicating compli-ance with the partial discharge test re-quirements in ANSI/ICEA S-94-649.

(2) Manufacturers shall test production sam-ples and have available certified testdata results indicating compliance withASTM D 2275 for discharge resistance asspecified in the ANSI/ICEA S-94-649.Samples of insulated cable shall be pre-pared by either removing the overlyingextruded insulation shield material, orusing insulated cable before the ex-truded insulation shield material is ap-plied. The sample shall be mounted asdescribed in ASTM D 2275 and shall besubjected to a voltage stress of 250 voltsper mil of nominal insulation thickness.The sample shall support this voltagestress, and not show evidence of degra-dation on the surface of the insulationfor a minimum test duration of 100 hours.The test shall be performed at least onceon each 50,000 feet (15,240 m) of cableproduced, or major fraction thereof, orat least once per insulation extruder run.

c. Jacket Tests. Tests described in this sectionshall be performed on cable jackets from thesame production sample as in section 11.bof this specification.

(1) A Cold Bend Test shall be performed inaccordance with the applicable provi-sions of the ANSI/ICEA S-94-649. Thetest temperature shall be -35°C (-31°F).


The sample shall show no cracks visibleto the normal, unaided eye at the con-clusion of the test. The test shall be per-formed at least once on each 50,000 feet(15,240 m) of cable produced, or majorfraction thereof, or at least once perjacket extruder run.

(2) A Spark Test shall be performed onnonconducting jacketed cable in accor-dance with ANSI/ICEA S-94-649 on 100percent of the completed cable prior toits being wound on shipping reels. Thetest voltage shall be 4.5 kV ac for cable

diameters <1.5 inches and 7.0 kV forcable diameters >1.5 inches., and shall beapplied between an electrode at the outersurface of the nonconducting jacket andthe concentric neutral for not less than0.15 second.

d. Frequency of sample tests shall be in accor-dance with ANSI/ICEA S-94-649.

e. If requested by the purchaser, a certifiedcopy of the results of all tests performed inaccordance to this section shall be furnishedon all orders.

E

12. Miscellaneous a. All cable provided under this specificationshall have suitable markings on the outersurface of the jacket at sequential intervalsnot exceeding two feet (0.61 m). The labelshall indicate the name of the manufacturer,conductor size, type and thickness of insula-tion, center conductor material, voltage rat-ing, year of manufacture, and jacket type.There shall be no more than six inches (0.15m) of unmarked spacing between text labelsequences. The jacket shall be marked withthe symbol required by Rule 350G of theNational Electrical Safety Code and the pur-chaser shall specify any markings requiredby local safety codes. This is in addition toextruded red stripes required in paragraph9.a. (1) of this specification.

b. Watertight seals shall be applied to all cableends to prevent the entrance of moisture dur-ing transit or storage. Each end of the cableshall be firmly and properly secured to the reel.

c. Cable shall be placed on shipping reels suit-able for protecting it from damage duringshipment and handling. After the cable iswound on the reel, it shall be covered witha suitable covering to help provide physicalprotection to the cable.

d. A durable label shall be securely attached toeach reel of cable. The label shall indicatethe purchaser’s name and address, purchaseorder number, cable description, reel num-ber, feet of cable on the reel, tare and grossweight of the reel, and beginning and end-ing sequential footage numbers.

404 – Appendix E

Underground Cable Specification

ATTACHMENT “A”

Cooperative Name: _________________________ Contact: __________________________________

Phone #: ____________ Fax #:______________ E-Mail: ___________________________________

Conductor Material: Aluminum Copper

Conductor Type: Solid Stranded

Conductor Size:__________________________________________________________________________

Voltage Rating: 15 kV 25 kV 35 kV

Conductor Shield Compound(s): ___________________________________________________________

Insulation Type: EPR TR-XLPE Either

Alternate Insulation Thickness: Min.________ Nominal _________ Max. _________

Alternate Insulation Compound(s): _________________________________________________________

Insulation Shield Compound(s): ____________________________________________________________

Neutral Design: Full 1/3 1/6 1/8 1/12

Outer Jacket Type: Semi-Conducting: Yes _______________ No________________

Reel Type: Returnable: Yes _______________ No________________

Wood Lagging Required: Yes _______________ No________________

Maximum Reel Size (inches): Width _____________ Diameter __________

Maximum Loaded Reel Weight (pounds): ____________________________________________________

Shipping Address:________________________________________________________________________

________________________________________________________________________

________________________________________________________________________

Shipping Method: Flanges parallel with trailer centerline

Flanges perpendicular to trailer centerline

Note: Axis of arbor holes must be horizontal

Additional Comments: ____________________________________________________________________

____________________________________________________________________

Signature: _______________________________________________________________________________

E

Al lowable Short Circuit Currents for Sol id Dielectr ic Insulated Cables – 405

Allowable Short CircuitCurrents for Solid DielectricInsulated CablesF

Figures F.1 through F.8 show the allowable shortcircuit current duration for common configura-tions of solid dielectric cable. Figures F.1, F.2,F.5, and F.6 assume the prefault conductor tem-perature is 75°C for cables with thermoplasticinsulation. Figures F.3, F.4, F.7, and F.8 assume aprefault conductor temperature of 90°C for ca-bles with thermoset insulation.Figures F.1, F.2, F.3, and F.4 use an upper

temperature limit that, if exceeded, wouldcause immediate permanent damage to thecable insulation.Figures F.5, F.6, F.7, and F.8 use the upper

temperature limit equal to the emergency ratingof the insulation that, if exceeded, adds incre-mentally to a loss of useful life of the cable.It is recommended that Figures F.5 through F.8

be used in the selection of overcurrent protec-tion system for cables. Usually, this will not posea problem in the overall coordination scheme.

Figure Time-Current Characteristic

F.1 PE/HMWPE Insulation, AluminumConductor, 150°C Final

F.2 PE/HMWPE Insulation, CopperConductor, 150°C Final

F.3 TR-XLPE/EPR Insulation, AluminumConductor, 250°C Final

F.4 TR-XLPE/EPR Insulation, CopperConductor, 250°C Final

F.5 PE/HMWPE Insulation, AluminumConductor, 90°C Final

F.6 PE/HMWPE Insulation, CopperConductor, 90°C Final

F.7 TR-XLPE/EPR Insulation, AluminumConductor, 130°C Final

F.8 TR-XLPE/EPR Insulation, CopperConductor, 130°C Final

406 – Appendix F

F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.1: Aluminum Conductor/Thermoplastic Insulation (PE/HMWPE). Allowable Short Circuit Currents Based on 75°CInitial Conductor Temperature and 150°C Final Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750


F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.2: Copper Conductor/Thermoplastic Insulation (PE/HMWPE). Allowable Short Circuit Currents Based on 75°CInitial Conductor Temperature and 150°C Final Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750

408 – Appendix F

F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.3: Aluminum Conductor/Thermoset Insulation (TR-XLPE/EPR). Allowable Short Circuit Currents Based on 90°CInitial Conductor Temperature and 250°C Final Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750


F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.4: Copper Conductor/Thermoset Insulation (TR-XLPE/EPR). Allowable Short Circuit Currents for 90°C RatedInsulation Based on 90°C Initial Conductor Temperature and 250°C Final Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750

410 – Appendix F

F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.5: Aluminum Conductor/Thermoplastic Insulation (PE/HMWPE). Allowable Short Circuit Currents for Conductorto Not Exceed Insulation Emergency Operating Temperature Rating Based on 75°C Initial Conductor Temperature and 90°CFinal Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750


F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.6. Copper Conductor/Thermoplastic Insulation (PE/HMWPE). Allowable Short Circuit Currents for Conductor toNot Exceed Insulation Emergency Operating Temperature Rating Based on 75°C Initial Conductor Temperature and 90°CFinal Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750

412 – Appendix F

F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.7: Aluminum Conductor/Thermoset Insulation (TR-XLPE/EPR). Allowable Short Circuit Currents for Conductor toNot Exceed Insulation Emergency Operating Temperature Rating Based on 90°C Initial Conductor Temperature and 130°CFinal Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750


F3,6003,000

2,400

1,800

1,200

600540480420360300

240

180

120

605448423630

24

18

12

6.05.44.84.23.63.0

2.4

1.8

1.2

.6

6050

40

30

20

1098765

4

3

2

1.9.8.7.6.5

.4

.3

.2

.1.09.08.07.06.05

.04

.03

.02

.01

100

200

300

400

500

600

700

800

900

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

20,0

00

30,0

00

40,0

00

50,0

00

Tim

e(C

ycle

s,60

-Her

tzBa

sis)

Tim

e(S

econ

ds)

6,00

0

7,00

08,

000

9,00

010

,000

Current (Amperes)

FIGURE F.8. Copper Conductor/Thermoset Insulation (TR-XLPE/EPR). Allowable Short Circuit Currents for Conductor toNot Exceed Insulation Emergency Operating Temperature Rating Based on 90°C Initial Conductor Temperature and 130°CFinal Conductor Temperature.

#2

#1

1/0

2/0

3/0

4/0250

350

500

750

Ampacity Tables – 415

Ampacity TablesGCable ampacity values shown in Appendix Gare based on calculations provided by OkoniteCompany for the 1992 edition of this manual.They have been retained because values areincluded for cases where the soil interface tem-perature between the cable and the soil, or be-tween the conduit and the soil, govern. WhileIEEE Standard 835-1994 does provide a more

comprehensive set of cable ampacity calcula-tions, the limiting ampacity for soil interfacetemperature criteria is not readily available fromthis Standard. It is suggested that both refer-ences be used to determine the ampacity limitsfor the circumstances under evaluation.A copy of Figure 4.10 is included at the end

of this appendix for reference.

75% Load Factor 100% Load Factor

Soil Interface Soil InterfaceConductor Size Amps Temp. Amps at 60ºC Amps Temp. Amps at 60ºC

4/0 (1/3 neutral) 390 69ºC 350 350 74ºC 308

350 (1/3 neutral) 506 72ºC 446 450 76ºC 385

500 (1/3 neutral) 603 74ºC 525 532 77ºC 445

750 (1/3 neutral) 689 75ºC 580 602 79ºC 495

1,000 (1/6 neutral) 804 76ºC 675 700 79ºC 575

TABLE G.1: Configuration No. 1—15-kV Copper.



1/0 (full neutral) 207 67ºC 192 187 71ºC 168

4/0 (1/3 neutral) 308 69ºC 278 276 73ºC 241

350 (1/3 neutral) 406 71ºC 364 362 75ºC 313

500 (1/3 neutral) 488 73ºC 426 432 77ºC 367

750 (1/3 neutral) 593 74ºC 512 521 78ºC 436

1,000 (1/6 neutral) 698 75ºC 596 609 78ºC 504

TABLE G.2: Configuration No. 1—15-kV Aluminum.

416 – Appendix G

G75% Load Factor 100% Load Factor


4/0 (1/3 neutral) 384 65ºC 361 346 70ºC 310

350 (1/3 neutral) 499 68ºC 454 445 73ºC 391

500 (1/3 neutral) 591 70ºC 528 522 74ºC 446

750 (1/3 neutral) 688 72ºC 602 602 76ºC 511

1,000 (1/6 neutral) 806 73ºC 698 703 77ºC 584





4/0 (1/3 neutral) 302 65ºC 287 272 70ºC 247

350 (1/3 neutral) 399 67ºC 373 357 72ºC 318

500 (1/3 neutral) 481 69ºC 435 427 73ºC 375

750 (1/3 neutral) 587 70ºC 526 517 75ºC 442

1,000 (1/6 neutral) 692 71ºC 619 606 75ºC 517




4/0 (1/3 neutral) 413 68ºC 376 364 73ºC 314

350 (1/3 neutral) 505 72ºC 442 438 77ºC 368

500 (1/3 neutral) 570 76ºC 483 489 79ºC 401

750 (1/3 neutral) 654 78ºC 535 557 81ºC 444

1,000 (1/6 neutral) 714 78ºC 558 606 82ºC 482





4/0 (1/3 neutral) 340 66ºC 317 301 71ºC 267

350 (1/3 neutral) 430 70ºC 385 376 75ºC 324

500 (1/3 neutral) 499 73ºC 433 431 77ºC 363

750 (1/3 neutral) 578 76ºC 485 494 80ºC 401

1,000 (1/6 neutral) 666 76ºC 565 570 79ºC 468





4/0 (1/3 neutral) 404 64ºC 388 358 70ºC 323

350 (1/3 neutral) 500 69ºC 454 437 74ºC 379

500 (1/3 neutral) 562 71ºC 496 487 76ºC 413

750 (1/3 neutral) 648 74ºC 554 556 78ºC 455

1,000 (1/6 neutral) 719 76ºC 606 613 80ºC 494





4/0 (1/3 neutral) 328 62ºC 320 293 68ºC 269

350 (1/3 neutral) 421 66ºC 393 371 71ºC 329

500 (1/3 neutral) 486 68ºC 445 425 73ºC 370

750 (1/3 neutral) 569 72ºC 498 491 76ºC 413

1,000 (1/6 neutral) 666 73ºC 577 572 77ºC 480


EXAMPLE G.1: Ampacity Reduction for Direct-Buried Versus Conduit Encasement for Flat-SpacedInstallation.


Soil Interface Amps Soil Interface AmpsConductor Size Amps Temp. at 60ºC Amps Temp. at 60ºC

750 (1/3 neutral) 467 55ºC 467 420 62ºC 408

TABLE G.9: Configuration No. 2, 3" Type DB Conduit—15-kV Aluminum.



750 (1/3 neutral) 479 55ºC 479 430 61ºC 424

TABLE G.10: Configuration No. 2, 3.5" Type DB Conduit—25-kV Aluminum.

Tables G.9 and G.10 show the effect of encasing the single cables of Configuration No. 2 in Type DB conduit insteadof direct burying the cables. Using conduit decreases ampacity by 19.2% for 15-kV cable and 15.82% for 25-kV cable.

418 – Appendix G


Conductor Size Amps Soil Interface Temp. Amps Soil Interface Temp.

4/0 (1/3 neutral) 307 46ºC 290 51ºC

350 (1/3 neutral) 407 47ºC 376 53ºC

500 (1/3 neutral) 474 49ºC 436 55ºC

750 (1/3 neutral) 557 49ºC 508 56ºC

1,000 (1/6 neutral) 649 50ºC 590 57ºC




1/0 (full neutral) 162 45ºC 152 50ºC

4/0 (1/3 neutral) 242 46ºC 226 52ºC

350 (1/3 neutral) 326 47ºC 302 53ºC

500 (1/3 neutral) 392 48ºC 361 55ºC

750 (1/3 neutral) 484 49ºC 441 56ºC

1,000 (1/6 neutral) 568 50ºC 516 57ºC




4/0 (1/3 neutral) 315 45ºC 293 51ºC

350 (1/3 neutral) 408 47ºC 377 54ºC

500 (1/3 neutral) 488 48ºC 447 55ºC

750 (1/3 neutral) 563 50ºC 513 57ºC

1,000 (1/6 neutral) 658 51ºC 597 57ºC




1/0 (full neutral) 169 44ºC 158 50ºC

4/0 (1/3 neutral) 249 45ºC 231 51ºC

350 (1/3 neutral) 327 47ºC 302 53ºC

500 (1/3 neutral) 401 47ºC 368 54ºC

750 (1/3 neutral) 485 49ºC 443 56ºC

1,000 (1/6 neutral) 570 50ºC 519 57ºC





4/0 (1/3 neutral) 357 73ºC 312 313 77ºC 266

350 (1/3 neutral) 463 75ºC 400 402 79ºC 337

500 (1/3 neutral) 537 77ºC 454 463 80ºC 379

750 (1/3 neutral) 616 78ºC 512 526 81ºC 423

1,000 (1/6 neutral) 717 79ºC 582 610 82ºC 484





4/0 (1/3 neutral) 281 73ºC 246 247 77ºC 210

350 (1/3 neutral) 369 74ºC 320 321 78ºC 270

500 (1/3 neutral) 441 76ºC 378 381 80ºC 314

750 (1/3 neutral) 532 77ºC 446 456 80ºC 374

1,000 (1/6 neutral) 624 78ºC 516 532 81ºC 431




4/0 (1/3 neutral) 352 69ºC 318 309 74ºC 270

350 (1/3 neutral) 454 72ºC 396 395 76ºC 335

500 (1/3 neutral) 534 74ºC 460 461 78ºC 385

750 (1/3 neutral) 618 76ºC 518 527 80ºC 434

1,000 (1/6 neutral) 719 76ºC 604 613 80ºC 498





4/0 (1/3 neutral) 277 69ºC 250 244 74ºC 213

350 (1/3 neutral) 364 71ºC 324 318 76ºC 273

500 (1/3 neutral) 436 73ºC 381 378 77ºC 317

750 (1/3 neutral) 528 74ºC 456 454 78ºC 380

1,000 (1/6 neutral) 620 75ºC 534 531 79ºC 439


420 – Appendix G



4/0 (1/3 neutral) 290 51ºC 290 264 57ºC 264

350 (1/3 neutral) 382 52ºC 382 345 59ºC 345

500 (1/3 neutral) 443 54ºC 443 398 61ºC 395

750 (1/3 neutral) 516 55ºC 516 459 62ºC 447

1,000 (1/6 neutral) 583 54ºC 583 532 63ºC 509





4/0 (1/3 neutral) 229 51ºC 229 209 57ºC 209

350 (1/3 neutral) 306 52ºC 306 277 58ºC 277

500 (1/3 neutral) 367 53ºC 367 330 60ºC 330

750 (1/3 neutral) 449 55ºC 449 400 62ºC 392

1,000 (1/6 neutral) 525 56ºC 525 466 63ºC 451




4/0 (1/3 neutral) 297 50ºC 297 270 57ºC 270

350 (1/3 neutral) 383 53ºC 383 345 59ºC 345

500 (1/3 neutral) 454 54ºC 454 406 61ºC 403

750 (1/3 neutral) 521 56ºC 521 463 63ºC 451

1,000 (1/6 neutral) 607 56ºC 607 538 64ºC 515





4/0 (1/3 neutral) 234 50ºC 234 213 57ºC 213

350 (1/3 neutral) 307 52ºC 307 277 59ºC 277

500 (1/3 neutral) 374 53ºC 374 335 60ºC 335

750 (1/3 neutral) 450 55ºC 450 401 62ºC 393

1,000 (1/6 neutral) 527 56ºC 527 468 63ºC 453





4/0 (1/3 neutral) 240 63ºC 233 209 70ºC 189

350 (1/3 neutral) 312 65ºC 296 268 71ºC 238

500 (1/3 neutral) 358 66ºC 333 306 73ºC 268

750 (1/3 neutral) 410 68ºC 375 348 74ºC 298

1,000 (1/6 neutral) 474 69ºC 429 400 75ºC 342





4/0 (1/3 neutral) 191 63ºC 186 166 69ºC 151

350 (1/3 neutral) 251 64ºC 238 216 71ºC 194

500 (1/3 neutral) 298 66ºC 278 255 72ºC 224

750 (1/3 neutral) 358 68ºC 328 304 74ºC 264

1,000 (1/6 neutral) 416 68ºC 381 352 75ºC 303




4/0 (1/3 neutral) 246 63ºC 235 213 70ºC 192

350 (1/3 neutral) 312 65ºC 296 268 72ºC 238

500 (1/3 neutral) 364 66ºC 339 310 73ºC 272

750 (1/3 neutral) 414 68ºC 378 350 74ºC 300

1,000 (1/6 neutral) 479 69ºC 430 405 75ºC 346





4/0 (1/3 neutral) 194 63ºC 187 167 70ºC 152

350 (1/3 neutral) 251 65ºC 238 216 71ºC 192

500 (1/3 neutral) 302 66ºC 283 257 72ºC 226

750 (1/3 neutral) 359 68ºC 329 304 74ºC 262

1,000 (1/6 neutral) 418 68ºC 380 354 75ºC 304


EXAMPLE G.2: Increase in Ampacity for Duct Bank Installation When Type EB Conduit is UsedVersus Schedule 40.

Tables G.27 and G.28 show the effect of using Type EB conduit instead of Schedule 40 for the concrete duct bankinstallation shown in Configuration No. 6. Using the thinner walled conduit gives an increase in ampacity ofapproximately 1.67% (see Configuration No. 6 of the ampacity tables and Figure 4.10).

422 – Appendix G

G



750 (1/3 neutral) 364 69ºC 331 307 75ºC 262

TABLE G.27: Configuration No. 6, 6" Type EB Conduit—15-kV Aluminum.



750 (1/3 neutral) 365 69ºC 332 308 75ºC 263

TABLE G.28: Configuration No. 6, 6" Type EB Conduit—25-kV Aluminum.



4/0 (1/3 neutral) 228 66ºC 215 196 72ºC 173

350 (1/3 neutral) 294 68ºC 270 250 74ºC 216

500 (1/3 neutral) 337 69ºC 303 285 75ºC 242

750 (1/3 neutral) 384 71ºC 342 322 76ºC 270

1,000 (1/6 neutral) 443 72ºC 390 371 77ºC 310





4/0 (1/3 neutral) 180 66ºC 170 155 72ºC 138

350 (1/3 neutral) 236 67ºC 219 201 74ºC 176

500 (1/3 neutral) 280 69ºC 255 237 75ºC 205

750 (1/3 neutral) 335 70ºC 299 282 76ºC 238

1,000 (1/6 neutral) 389 71ºC 345 326 77ºC 275





4/0 (1/3 neutral) 232 66ºC 218 198 72ºC 175

350 (1/3 neutral) 294 68ºC 270 250 74ºC 215

500 (1/3 neutral) 342 69ºC 307 288 75ºC 245

750 (1/3 neutral) 387 71ºC 341 324 77ºC 272

1,000 (1/6 neutral) 448 72ºC 390 374 77ºC 310





4/0 (1/3 neutral) 183 66ºC 172 156 72ºC 138

350 (1/3 neutral) 236 67ºC 219 201 74ºC 175

500 (1/3 neutral) 283 69ºC 258 239 75ºC 206

750 (1/3 neutral) 336 70ºC 300 282 76ºC 238

1,000 (1/6 neutral) 391 71ºC 346 327 77ºC 276


FIGURE 4.10: Three-Phase Cable Installation Configurations.

Configuration 1

36"

36" 30"

19"

7.5"

7.5”

18"

19"

19" × 19" Duct Bank

7.5"

5"

30"

19"

7.5" 7.5"

7.5"

26.5"

19" × 26.5" Duct Bank

5"

18"

36"

36"

36"



A B C

Industry Speci f icat ions – 425

Industry SpecificationsH1. RUS Bulletin 1728C-100

List of Materials Acceptable for Use onSystems of RUS Electrification Borrowers

2. IEEE Standard 404Standard for Extruded and LaminatedDielectric Shielded Cable Joints Rated2,500 V to 500,000 V

3. IEEE Standard 592Exposed Semiconducting Shields onHigh-Voltage Cable Joints and SeparableInsulated Connectors

4. IEEE Standard 48Standard Test Procedures and Requirementsfor Alternating-Current Cable Terminations2.5 kV through 765 kV

5. NEMA/ANSI C 119.0Sealed Insulated Underground ConnectorSystems Rated 600 Volts

6. RUS Bulletin 1728F-U1RUS Specification for 15-kV, 25-kV, and35-kV Primary Underground Power Cable

7. RUS Bulletin 50-6 (D-806)Specifications and Drawings forUnderground Electric Distribution

8. ICEA S-81-570Standard for 600-Volt-Rated Cables ofRuggedized Design for Direct BurialInstallation as Single Conductors orAssemblies of Single Conductors

9. ICEA S-105-692600-Volt Single Layer Thermoset InsulatedUtility Underground Distribution Cables

10. ANSI/ICEA S-94-649Concentric Neutral Cables Rated 5through 46 kV

11. ANSI/ICEA S-97-682Utility Shielded Power Cables Rated 5through 46 kV

12. IEEE Standard 495Guide for Testing Faulted Circuit Indicators

13. ANSI/IEEE C57.91IEEE Guide for Loading Mineral-Oil-Immersed Overhead and Pad-MountedDistribution Transformers Rated 500 kVAand Less with 65°C or 55°C AverageWinding Rise

14. BSR/IEEE C57.12.00Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulat-ing Transformers

15. IEEE Standard C12.26Pad-Mounted Compartmental-Type,Self-Cooled, Three-Phase DistributionTransformers for Use with SeparableInsulated High-Voltage Connectors(34,500 Grd Y/19,920 Volts and Below,2,500 kVA and Smaller)

16. IEEE Standard 835Standard Power Cable Ampacity Tables

17. NEMA MG 1-12.35Locked-Rotor Current of 3-Phase 60-HzSmall and Medium Squirrel-CageInduction Motors Rated at 230 Volts

18. IEEE Standard C62.11Standard for Metal-Oxide SurgeArresters for AC Power Circuits (>1 kV)

426 – Appendix H

19. IEEE Standard C62.1Standard for Gapped Silicon-CarbideSurge Arresters for AC Power Circuits

20. IEEE Standard 81Guide for Measuring Earth Resistivity,Ground Impedance, and Earth SurfacePotentials of a Ground System

21. IEEE Standard 80Guide for Safety in AC Substation Grounding

22. RUS Bulletin 169-4

Voltage Levels on Rural Distribution Systems23. IEEE Standard 386

Standard for Separable Insulated ConnectorSystems for Power Distribution SystemsAbove 600 V

24. REA Bulletin U2February 1975. Out of print but may beavailable by special request to RUS Electricstaff, Washington, D.C.

H

Component Manufacturers – 427

Component ManufacturersITrack-

Guided Piercing Hydraulic Mounted Trench Auger-TypeManufacturer Trenchers Backhoes Cable Plow Boring Tools Tools Pipe Pusher Cable Plows Compactors Boring Tools

Am. Augers X

Ditch Witch X X X X X

Cleveland Trencher Co. X

Holladay Constr. Co. X

Pow-r-Devices X

StraightLine Mfg. Co. X

UtilX Corp. X

Vermeer Mfg. Co. X X X X X X

American Augers, Inc. Holladay Construction Co., Inc. UtilX Corp.135 US Route 42 5419 Hickory Ridge Road P.O. Box 97009P.O. Box 814 Spotsylvania, VA 22553 Kent, WA 98064-9709West Salem, OH 44287 540.582.2700 800.252.0556800.324.4930 www.holladayconstco.com www.utilx.comwww.american-augers.com

The Charles Machine Works, Inc. Pow-r-Devices, Inc. Vermeer Manufacturing Co.(Manufacturer of Ditch Witch Equipment) 5940 Goodrich Road 1210 Vermeer Road EastP.O. Box 66 Clarence Center, NY 14032-0245 P.O. Box 200Perry, OK 73077-0066 800.344.6653 Pella, IA 50219800.654.6481 www.powrdevices.com 641.628.3141www.ditchwitch.com www.vermeer.com

Cleveland Trencher Co. StraightLine Manufacturing, Inc.1755 West Market Street (Finco Inc.)Akron, OH 44313 1816 East Wasp Road330.869.2800 Hutchinson, KS 67501www.cleveland-trencher.com 800.654.3484

www.straightlinehdd.com

TABLE I.1: Cable Installation Equipment Manufacturers.

428 – Appendix I

IJoints— Terminations—

Joints— Elbows— Secondary SecondaryPrimary Circuits Primary Circuits Terminations—Primary Circuits Circuits Circuits

Heat Elbow Heat Cold Above All Above AllManufacturer Premolded Shrink Premolded Connectors Premolded Porcelain Shrink Shrink Ground Locations Ground Locations

3M Elec. Prod. X X X X X

Amp Inc. X X X X

Burndy Corp. X X X X

Cooper Power X X X XSystems - RPE

Elastimold, X X X X X X X X XThomas & Betts

Fargo Mfg. Co. X X X X

G&W Electric Co. X

Homac Mfg. Co. X X X X

Kearney X X

Raychem Corp. X X X X X X X

Reliable Elec. X X X XProd.

TABLE I.2: Cable Installation Equipment Manufacturers.

3M Electric Products Division6801 River Place RoadAustin, TX 78726800.245.3573www.mmm.com

AMP Inc. (Tyco)P.O. Box 3608Harrisburg, PA 17105www.amp.com

Burndy Corporation825 Old Trail RoadEtters, PA 17319800.346.4175www.fciconnect.com

Cooper Power SystemsComponents & Protective Equipment1045 Hickory StreetPewaukee, WI 53072www.cooperpower.com

Elastimold, Thomas & Betts8155 T&B Blvd.Memphis, TN 38125888.862.3289www.tnb.com

Fargo Mfg. Co. (Hubbell)210 N. Allen StreetCentralia, MO 65240www.hubbellpowersystems.com

G&W Electric Co., Inc.3500 West 127th StreetBlue Island, IL 60406708.388.5010www.gwelec.com

Homac Mfg. Co.12 Southland RoadOrmond Beach, FL 32174386.673.5025www.homac.com

Kearney (Cooper Power Systems)1319 Lincoln AvenueWaukesha, WI 53186262.524.3300www.cooperpower.com

Raychem Corp.Tyco Electronics Corp.300 Constitution DriveMenlo Park, CA 94025-1164650.361.3333www.raychem.com

Reliable Electrical ProductsMacLean Power Systems1000 Allanson RoadMundelein, IL 60060847.566.0010www.maclean-fogg.com

Component Manufacturers – 429

IElbowElbow Accessories

Cable Jacket & TerminationManufacturer Plugs Adapters Inserts Restoration Kits Sealing Kits Grounding Kits

3M Electric Products X X X X X X

Cooper Power Systems X X X

Elastimold, Thomas & Betts X X X X X X

Homac Mfg. X X X

Raychem X X X

TABLE I.3: Manufacturers of Joint, Elbow, and Termination Accessories and Kits.

Sources of DC Proof Test Equipment

Associated Research, Inc. Biddle Instruments Hipotronics, Inc. The Von Corporation13860 W. Laurel Drive 510 Township Line Road 1620 Route 22 1038 Lomb Avenue, S.W.Lake Forest, IL 60045 Blue Bell, PA 19422 P.O. Box 414 P.O. Box 110096800.858.8378 866.586.3872 Brewster, NY 10509 Birmingham, AL 35211www.asresearch.com www.avobiddle.com 845.279.8091 205.788.2437

www.hipotronics.com www.voncorp.com

TABLE I.4. Partial Listing of Cable Testing Equipment Suppliers.

Cable-Pul l ing Examples – 431

Cable-Pulling ExamplesJEXAMPLE J.1: Cable-Pulling Example 1: Maximum Straight-Pull Distance for Three 25-kV Cables Installed inFive-Inch PVC Conduit.

Determine the maximum straight-pull distance for three 25-kV cables installed in five-inch PVC conduit. The following specific dataapply in this situation:

Cable Type: Aluminum, EPR, 25 kV, with 1/3 neutralCable Jacket: PolyethyleneCable Size: 350 kcmilCable Weight (Each): 1.64 lb./ft

The solution sequence follows the procedure given in the main text under Cable-Pulling Calculation Sequence.

STEPS 1 and 2. Determine the cable and conduit data. These arereadily determined from the data above. For a three-cable pull, cableweight is three times 1.64 lb./ft, yielding 4.92 lb./ft.

STEP 3. Determine the friction factors. Table 9.16 gives a frictionfactor of 0.45 for three polyethylene jacketed cables installed in PVCconduit in a straight-pull situation.

STEP 4(a). Calculate the jam ratio. The jam ratio is calculated fromEquation 9.9.

J = = = 2.76Dd

5.047 inches1.83 inches

This jam ratio value would be risky if bends were present in the con-duit. However, the value of 2.76 is acceptable for straight pulls.

STEP 4(b). Calculate the clearance factor. According to Equation9.11, the clearance factor is 1.13 inches. This value is well above the0.5-inch minimum acceptable value.

STEP 4(c). Calculate the weight correction factor. Before cal-culating the weight correction factor, determine if the three cables willtake on a triangular or a cradled configuration.

Table 9.19 shows that either configuration is likely when the jam ratiois 2.76. Therefore, a cradled configuration should be assumed becauseit leads to more conservative results. The weight correction factor cannow be calculated from Equation 9.4:

Wc = 1 + × = 1.4324

31.83

5.047 – 1.83

STEP 5(a). Determine the maximum allowable cable tension.Table 9.20 gives a value of 0.008 lb./cmil maximum pulling tensionwhen an aluminum compression eye is used on stranded aluminumcable. The maximum tension for one 350-kcmil cable is:

2 × 2,800 lb. = 5,600 lb.

350,000 cmil × 0.008 lb./cmil = 2,800 lb.

When three cables are being pulled, the maximum allowable tensionis determined by doubling the tension maximum of one cable, as it isassumed that the total load will be shared by two of the three cables.Therefore, the maximum allowable tension for the sample situation isas follows:

Cable Outside Diameter: 1.83 in.Conduit Inside Diameter: 5.047 in.Pulling Lubricant: Soap and waterType of Attachment: Aluminum compression

Continued

432 – Appendix J

JEXAMPLE J.1: Cable-Pulling Example 1: Maximum Straight-Pull Distance for Three 25-kV Cables Installed inFive-Inch PVC Conduit. (cont.)

STEP 5(b). Determine the maximum allowable sidewall bear-ing pressure (SWBP). Consult Table 9.18 for this purpose. The max-imum allowable SWBP is 2,000 lb./ft for jacketed EPR cable. However,SWBP is not a concern for straight pulls.

STEP 6(a). Calculate the pulling tension per foot. Pulling tensionfor straight pulls is calculated from Equation 9.3:

STEP 6(b). Determine the maximum straight-pull distance. As-sume 50 lb. of tension exists from the cable reel to the conduit en-trance. Since the maximum allowable tension is 5,600 lb., a tension of5,600 lb. less 50 lb. (5,550 lb.) is allowed for pulling tension. Therefore,the maximum pulling distance is calculated as follows:

IMAX = = 1,753 ft5,550 lb.3.166 lb./ft

T = W×WC × f ×lT(1 foot) = 4.92 lb./ft × 1.43 × 0.45 × 1 ftT(1 foot) = 3.166 lb.

EXAMPLE J.2: Cable-Pulling Example 2: Feasibility of Pulling Three 25-kV Cables into a Six-Inch PVC Conduit.

Determine the feasibility of pulling three cables of the same type described in Example J.1 into an installation of six-inch PVC con-duit consisting of the following sections:

A. 100-foot horizontal straight pull beginning at a manhole locationB. 22-1/2° bend and beginning of upward slopeC. 500-foot upward 1:20 slope

The cable-reel end is to be at the manhole and the pulling end at the riser.

STEPS 1 and 2. Determine the cable and conduit data. Cabledata, lubricant, and type of grip are the same as given in Example J.1.For Example J.2, six-inch conduit of 6.065 inches inside diameter is tobe used.

STEP 3. Determine the friction factors. For three polyethylene-jacketed cables installed in PVC conduit, Table 9.16 gives a friction fac-tor of 0.45 for straight pulls and 0.15 for pulls through bends whereSWBP exceeds 150 lb./ft.

STEP 4(a). Calculate the jam ratio. The jam ratio is calculated fromEquation 9.9:

J = = = 3.31Dd

6.065 inches1.83 inches

This jam ratio value is acceptable.

STEP 4(b). Calculate the clearance factor. The clearance factor iscalculated from Equation 9.11 and is found to be 2.2 inches. Thisgreatly exceeds the 0.5-inch required minimum.

STEP 4(c). Calculate the weight correction factor. Table 9.19 re-veals that the cables will take on a cradled configuration for the jamratio of 3.31 calculated above. Therefore, Equation 9.4 is used to cal-culate the weight correction factor:

Wc = 1 + × = 1.2524

31.83

6.065 – 1.83

STEP 5(a). Determine the maximum allowable cable tension.This tension limit calculation is identical to that found in Example J.1.The maximum allowable pulling tension is 5,600 lb.

STEP 5(b). Determine the maximum allowable SWBP. Table 9.18is consulted for this purpose, and the maximum allowable SWBP isfound to be 2,000 lb./ft for jacketed EPR cable.

STEP 6(a). Calculate the tension for the 100-foot horizontalstraight pull beginning at the manhole location. The tension cal-culated by Equation 9.3 is added to the entering tension from the reel,which is assumed to be 50 lb.

T2 = T1 + W×WC × f ×lT2 = 50 + (4.92)(1.25)(0.45)(100) = 327 lb.

D. 90° bend at base of riser poleE. 30-foot vertical section at riser pole

Continued

Cable-Pul l ing Examples – 433

JEXAMPLE J.2: Cable-Pulling Example 2: Feasibility of Pulling Three 25-kV Cables into a Six-Inch PVC Conduit. (cont.)

STEP 6(b). Calculate the tension for the 22-1/2° bend. Equation9.3.C applies for calculating the tension increase resulting from pullingaround conduit bends. SWBP is not expected to exceed 150 lb./ft forthis bend, so the friction factor of 0.45 is used. The angle of the bendmust be stated in radians, and 22-1/2° is 22.2 × 0.01745 radians/degree= 0.3927 radians. T1 is the tension result from the previous steps.

STEP 6(d). Calculate the tension for the 90° bend at the baseof the riser pole. At this location, cable tension has increased to thepoint that SWBP is expected to exceed 150 lb./ft. Therefore, the fric-tion factor of 0.15 for bends may be used (see Table 9.16). The 90°angle of bend converts to 1.5708 radians. Equation 9.3.C is used.

T2 = T2 + lW(fWC cosθ + sinθ)T2 = 408 + (500)(4.92)[(0.45)(1.25)(0.99875) + 0 .05]T2 = 408 + (2,460)(0.6118) = 408 + 1,505 = 1,913 lb.

T2 = T1ef × WC × φ

T2 = (327)e(0.45)(1.25)(0.3927) = 406 lb.

When a bend is involved, SWBP must also be calculated. Equation 9.7applies in the present case. The typical value for R, the inside radiusof a bend, for six-inch conduit is 2.75 feet.

SWBP = =(3WC – 2)T2

3R(3.75 – 2)(408)

(3)(2.75)= 87 lb./ft

SWBP = =(3WC – 2)T2

3R(3.75 – 2)2,568

(3)(2.75)= 545 lb./ft

This result is far less than the 2,000 lb./ft limit and is fully acceptable.As expected, the value is also less than 150 lb./ft, confirming the useof 0.45 as the correct friction factor.

STEP 6(c). Calculate the tension for the 500-foot upward 1:20slope. Equation 9.5.A applies in this case. As a preliminary step, theslope angle, θ, is calculated from the 1:20 slope ratio:

θ = Tan–1 = 2.86º120

Equation 9.5.A is then applied as an increment to the tension T1of 408 lb. from the previous step.

T2 = (1,913)e(0.15)(1.25)(1.5708) = 2,568 lb.

The calculation of SWBP is also required. The radius of the bend is as-sumed to be 2.75 feet, and Equation 9.7 applies.

The result is well within the 2,000 lb./ft allowed maximum. It is alsoabove the 150 lb./ft value necessary to allow use of 0.15 as the fric-tion factor.

STEP 6(e). Calculate the tension for the 30-foot vertical sec-tion at the riser pole. A vertical rise is equivalent to an upward slopeof 90°, so Equation 9.5.A applies. The evaluations cos 90° = 0 and sin90° = 1 yield the following simplified form of the tension equation:

T2 = T1 + lW = 2,568 + (30)(4.92)T2 = 2,568 + 148 = 2,716 lb.

This result for final tension is less than half the 5,600-lb. maximumallowed, so the proposed cable-pulling operation is feasible.

Abbreviat ions – 435

abbreviat ions

Ω-m Ohm-meters (Ohm-m), a unit of mea-sure for volume resistivity

µH Microhenry, one-millionth of a Henryµm Micrometer, one-millionth of a meterµs Microsecond, one-millionth of

a second%Z Percentage Impedance

ABS Acrylonitrile-Butadiene-Styrene Plasticac Alternating Current (sometimes AC)AEIC Association of Edison Illuminating

CompaniesANSI American National Standards InstituteASAI Average Service Availability IndexASTM American Society for Testing

and MaterialsAWG American Wire Gauge

BCN Bare Concentric NeutralBIL Basic Impulse Insulation Level

CATV Cable Access Televisioncm Centimetercmil Circular MilCont. ContinuousCPE Chlorinated PolyethyleneCRN NRECA’s Cooperative Research

NetworkCTR Certified Test ResultsCu Chemical symbol for CopperCV Continuous VulcanizingCWW Chopped Wave Withstand

DB Direct Burial (conduit classification)dc Direct Current (sometimes DC)di/dt Change in Current with Time (usually

expressed as kA/µs)

EB Encased Burial (conduit classification)EC Electrical Conductor (grade of

aluminum)EMT Electrical Metallic TubingEPR Ethylene Propylene RubberEPRI Electric Power Research InstituteEVA Ethyl Vinyl Acetate

FCI Faulted-Circuit IndicatorFOW Front-of-WaveFRE Fiberglass-Reinforced Epoxy

H Henry, a unit of inductance

HDPE High-Density PolyethyleneHMWPE High-Molecular-Weight PolyethyleneHp HorsepowerHV High VoltageHVAC Heating, Ventilation, and Air

ConditioningHz Hertz

IACS International Annealed CopperStandard

ICEA Insulated Cable EngineersAssociation, Inc.

I.D. Inside DiameterIEEE Institute of Electrical and

Electronics Engineersin2 Square InchesIR Any Product of Current (I) Times

Resistance (R)IZSURGE Current Times Surge Impedance

JCN Jacketed Concentric Neutral

kA Kiloampereskcmil Thousand Circular Mil, wire size

commonly used for multiple strandedconductors over 4/0 AWG in size(formerly MCM)

kft Kilofoot (1,000 feet)ksi Kips Per Square Inch (Thousands of

Pounds Per Square Inch)kV Kilovolt (1,000 Volts)kVA Kilovolt AmpereskV/ft Kilovolts Per FootkW Kilowatt

L Inductancelb. Pound(s)L.C. Longitudinally CorrugatedLDPE Low-Density PolyethyleneLLDPE Linear Low-Density Polyethylene

mA Milliampere, One-Thousandthof an Ampere

MCM See KcmilMCOV Maximum Continuous Operating

VoltageMDPE Medium-Density PolyethyleneMGN Multigrounded NeutralMOV Metal Oxide Varistor, a type of

surge arrestermm2 Square Millimeters

mm3 Cubic MillimetersMVA Megavolt Amperes

NEC National Electrical CodeNEMA National Electrical Manufacturers

AssociationNESC National Electrical Safety CodenF NanoFarad (Billionth of a Farad)Nom. NominalNRECA National Rural Electric Cooperative

Association

O.D. Outside DiameterOhm-m Ohm-meters, a unit of measure for

volume resistivity

PE Polyethyleneppm Parts Per Millionpsi Pounds Per Square Inchpsia Pounds Per Square Inch Absolutepsig Pounds Per Square Inch Gaugepu Per UnitPVC Polyvinyl Chloride

REA Rural Electrification Administrationrms Root Mean SquareROW Right of WayRTU Remote Terminal UnitRUS Rural Utility Services, U.S. Department

of Agriculture Rural Development—Electric Program (formerly REA)

SAIDI System Average InterruptionDuration Index

SF6 Sulfur Hexafluoride, a synthetic gasused to insulate high-voltage equip-ment and serve as an interruptingmedium in switchgear, one of sixtypes of greenhouse gases to becurbed under the Kyoto Protocol

SiC Silicon Carbide, used in valve arrestersSIW Single Input WireSLG Single Line-to-Ground (Fault)SR State RoadSWBP Sidewall Bearing PressureSym. Symmetrical

TNA Transient Network AnalyzerTOV Temporary OvervoltagesTR-XLPE Tree Retardant Cross-Linked

Polyethylene

UD Underground Distribution

V Volt

W Watt

XLPE Cross-Linked PolyethyleneX/R Reactance/Resistance (Ratio)

ZnO Zinc OxideZSURGE Surge Impedance

436 – Abbreviat ions

abbreviat ions

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56177126 Underground Distribution System Design Guide

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