Drilling Design Manual

7/31/2019 Drilling Design Manual

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ARPO

ENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 230

STAP P 1 M 6100

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was given

TITLE

DRILLING DESIGN MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion UnitsSTAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a

CD-Rom version can also be distributed (requests will be addressed to STAP Dept. inEni - Agip Division Headquarter)

Date of issue:

Issued by P. MagariniE. Monaci

C. Lanzetta A. Galletta

28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99


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IDENTIFICATION CODE PAGE 2 OF 230

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INDEX

1. INTRODUCTION 9

1.1. PURPOSE AND OBJECTIVES 9

1.2. IMPLEMENTATION 9

1.3. UPDATING, AMENDMENT, CONTROL& DEROGATION 9

2. PRESSURE EVALUATION 10

2.1. FORECAST ON PRESSURE AND TEMPERATURE GRADIENTS 10

2.2. OVERPRESSURE EVALUATION 112.2.1. Methods Before Drilling 122.2.2. Methods While Drilling 122.2.3. Real Time Indicators 132.2.4. Indicators Depending on Lag Time 142.2.5. Methods After Drilling 16

2.3. TEMPERATURE PREDICTION 192.3.1. Temperature Gradients 202.3.2. Temperature Logging 20

3. SELECTION OF CASING SEATS 21

3.1. CONDUCTOR CASING 243.2. SURFACE CASING 24

3.3. INTERMEDIATE CASING 24

3.4. DRILLING LINER 25

3.5. PRODUCTION CASING 25

4. CASING DESIGN 26

4.1. INTRODUCTION 26

4.2. PROFILES AND DRILLING SCENARIOS 27

4.2.1. Casing Profiles 27

4.3. CASING SPECIFICATION AND CLASSIFICATION 284.3.1. Casing Specification 284.3.2. Classification Of API Casing 29

4.4. MECHANICAL PROPERTIES OF STEEL 294.4.1. General 294.4.2. Stress-Strain Diagram 29

4.5. NON-API CASING 31

4.6. CONNECTIONS 324.6.1. API Connections 32

4.7. APPROACH TO CASING DESIGN 334.7.1. Wellbore Forces 334.7.2. Design Factor (DF) 344.7.3. Design Factors 35


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4.7.4. Application of Design Factors 35

4.8. DESIGN CRITERIA 364.8.1. Burst 36

4.8.2. Collapse 394.8.3. Tension 42

4.9. BIAXIAL STRESS 434.9.1. Effects On Collapse Resistance 434.9.2. Company Design Procedure 454.9.3. Example Collapse Calculation 46

4.10. BENDING 474.10.1. General 474.10.2. Determination Of Bending Effect 474.10.3. Company Design Procedure 494.10.4. Example Bending Calculation 50

4.11. CASING WEAR 524.11.1. General 524.11.2. Volumetric Wear Rate 534.11.3. Wear Factors 554.11.4. Wear Allowance In Casing Design 564.11.5. Company Design Procedure 57

4.12. SALT SECTIONS 584.12.1. Company Design Procedure 59

4.13. CORROSION 604.13.1. Exploration And Appraisal Wells 604.13.2. Development Wells 604.13.3. Contributing Factors To Corrosion 614.13.4. Casing For Sour Service 634.13.5. Ordering Specifications 634.13.6. Company Design Procedure 64

4.14. TEMPERATURE EFFECTS 684.14.1. Low Temperature Service 68

4.15. LOAD CONDITIONS 694.15.1. Safe Allowable Pull 694.15.2. Cementing Considerations 694.15.3. Pressure Testing 704.15.4. Company Guidelines 704.15.5. Hang-Off Load (LH) 71

5. MUD CONSIDERATIONS 72

5.1. GENERAL 72

5.2. DRILLING FLUID PROPERTIES 725.2.1. Cuttings Lifting 725.2.2. Subsurface Well Control 735.2.3. Lubrication 745.2.4. Bottom-Hole Cleaning 745.2.5. Formation Evaluation 745.2.6. Formation Protection 74

5.3. MUD COMPOSITION 75

5.3.1. Salt Muds 755.3.2. Water Based Systems 785.3.3. Gel Systems 795.3.4. Polymer Systems 79


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5.3.5. Oil Based Mud 80

5.4. SOLIDS 80

5.5. DENSITY CONTROL MATERIALS 81

5.6. FLUID CALCULATIONS 81

5.7. MUD TESTING PROCEDURES 84

5.8. MINIMUM STOCK REQUIREMENTS 85

6. FLUID HYDRAULICS 87

6.1. HYDRAULICS PROGRAMME PREPARATION 87

6.2. DESIGN OF THE HYDRAULICS PROGRAMME 88

6.3. FLOW RATE 88

6.4. PRESSURE LOSSES 906.4.1. Surface Equipment 936.4.2. Drill Pipe 936.4.3. Drill Collars 936.4.4. Bit Hydraulics 936.4.5. Mud Motors 946.4.6. Annulus 94

6.5. USEFUL TABLES AND CHARTS 95

7. CEMENTING CONSIDERATIONS 97

7.1. CEMENT 977.1.1. API Specification 977.1.2. Slurry Density and Weight 100

7.2. CEMENT ADDITIVES 1027.2.1. Accelerators 1027.2.2. Retarders 1037.2.3. Extenders 1037.2.4. Weighting Agents 104

7.3. SALT CEMENT 105

7.4. SPACERS AND WASHES 106

7.5. SLURRY SELECTION 107

7.6. CEMENT PLACEMENT 108

7.7. WELL CONTROL 108

7.8. JOB DESIGN 1107.8.1. Depth/Configuration 1107.8.2. Environment 1117.8.3. Temperature 1117.8.4. Slurry Preparation 111

8. WELLHEADS 112

8.1. DEFINITIONS 112

8.2. DESIGN CRITERIA 1128.2.1. Material Specification 112


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8.3. SURFACE WELLHEADS 1138.3.1. Standard Wellhead Components 1138.3.2. National/Breda Wellhead Systems 113

8.4. COMPACT WELLHEAD 116

8.5. MUDLINE SUSPENSION 119

9. PRESSURE RATING OF BOP EQUIPMENT 122

9.1. BOP SELECTION CRITERIA 122

10. BHA DESIGN AND STABILISATION 125

10.1. STRAIGHT HOLE DRILLING 125

10.2. DOG-LEG AND KEY SEAT PROBLEMS 12510.2.1. Drill Pipe Fatigue 12510.2.2. Stuck Pipe 12610.2.3. Logging 12610.2.4. Running casing 12610.2.5. Cementing 12610.2.6. Casing Wear While Drilling 12610.2.7. Production Problems 126

10.3. HOLE ANGLE CONTROL 12810.3.1. Packed Hole Theory 12810.3.2. Pendulum Theory 129

10.4. DESIGNING A PACKED HOLE ASSEMBLY 129

10.4.1. Length Of Tool Assembly 12910.4.2. Stiffness 12910.4.3. Clearance 13110.4.4. Wall Support and Length of Contact Tool 131

10.5. PACKED BOTTOM HOLE ASSEMBLIES 131

10.6. PENDULUM BOTTOM HOLE ASSEMBLIES 133

10.7. REDUCED BIT WEIGHT 134

10.8. DRILL STRING DESIGN 135

10.9. BOTTOM HOLE ASSEMBLY BUCKLING 138

10.10.SUMMARY RECOMMENDATIONS FOR STABILISATION 140

10.11.OPERATING LIMITS OF DRILL PIPE 142

10.12.GENERAL GUIDELINES 142

11. BIT SELECTION 143

11.1. PLANNING 143

11.2. IADC ROLLER BIT CLASSIFICATION 14311.2.1. Major Group Classification 14411.2.2. Bit Cones 145

11.3. DIAMOND BIT CLASSIFICATION 146

11.3.1. Natural Diamond Bits 14611.3.2. PDC Bits 14611.3.3. IADC Fixed Cutter Classification 146


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11.4. BIT SELECTION 14811.4.1. Formation Hardness/Abrasiveness 14811.4.2. Mud Types 149

11.4.3. Directional Control 14911.4.4. Drilling Method 15011.4.5. Coring 15011.4.6. Bit Size 150

11.5. CRITICAL ROTARY SPEEDS 150

11.6. DRILLING OPTIMISATION 152

12. DIRECTIONAL DRILLING 153

12.1. TERMINOLOGY AND CONVENTIONS 153

12.2. CO-ORDINATE SYSTEMS 155

12.2.1. Universal Transverse Of Mercator (UTM) 15512.2.2. Geographical Co-ordinates 156

12.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 15812.3.1. Horizontal Displacement 15812.3.2. Target Direction 15912.3.3. Convergence 159

12.4. HIGH SIDE OF THE HOLE AND TOOL FACE 16012.4.1. Magnetic Surveys 16112.4.2. Gyroscopic Surveys 16312.4.3. Survey Calculation Methods 16512.4.4. Drilling Directional Wells 16712.4.5. Dog Leg Severity 172

13. DRILLING PROBLEM PREVENTION MEASURES 173

13.1. STUCK PIPE 17313.1.1. Differential Sticking 17413.1.2. Sticking Due To Hole Restrictions 17513.1.3. Sticking Due To Caving Hole 17613.1.4. Sticking Due To Hole Irregularities And/Or Change In BHA 178

13.2. OIL PILLS 17913.2.1. Light Oil Pills 17913.2.2. Heavy Oil Pills 17913.2.3. Acid Pills 180

13.3. FREE POINT LOCATION 18113.3.1. Measuring The Pipe Stretch 18113.3.2. Location By Free Point Indicating Tool 18213.3.3. Back-Off Procedure 182

13.4. FISHING 18313.4.1. Inventory Of Fishing Tools 18313.4.2. Preparation 18313.4.3. Fishing Assembly 184

13.5. FISHING PROCEDURES 18413.5.1. Overshot 18413.5.2. Releasing Spear 184

13.5.3. Taper Taps 18513.5.4. Junk basket 18513.5.5. Fishing Magnet 185


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13.6. MILLING PROCEDURE 186

13.7. JARRING PROCEDURE 187

14. WELL ABANDONMENT 189

14.1. TEMPORARY ABANDONMENT 18914.1.1. During Drilling Operations 18914.1.2. During Production Operations 189

14.2. PERMANENT ABANDONMENT 19014.2.1. Plugging 19014.2.2. Plugging Programme 19014.2.3. Plugging Procedure 191

14.3. CASING CUTTING/RETRIEVING 19214.3.1. Stub Termination (Inside a Casing String) 192

14.3.2. Stub Termination (Below a Casing String) 192

15. WELL NAME/DESIGNATION 193

15.1. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND TARGET 193

15.1.1. Vertical Well 19315.1.2. Side Track In A Vertical Well. 19315.1.3. Directional Well 19415.1.4. Side Track In Directional Well 19415.1.5. Horizontal Well 19415.1.6. Side Track In A Horizontal Well 194

15.2. WELLS WITH THE ORIGINAL WELL HEAD CO-ORDINATES AND DIFFERENT TARGETS 195

15.3. WELLS WITH DIFFERENT WELL HEAD CO-ORDINATES AND SAME ORIGINAL TARGETS197

15.4. FURTHER CODING 198

16. GEOLOGICAL DRILLING WELL PROGRAMME 200

16.1. PROGRAMME FORMAT 200

16.2. IDENTIFICATION 200

16.3. GRAPHIC REPRESENTATIONS 200

16.4. CONTENTS OF THE GEOLOGICAL AND DRILLING WELL PROGRAMME 20116.4.1. General Information (Section 1) 20116.4.2. Geological Programme (Section 2) 20716.4.3. Operation Geology Programme (Section 3) 20816.4.4. Drilling Programme (Section 4) 209

17. FINAL WELL REPORT 210

17.1. GENERAL 210

17.2. FINAL WELL REPORT PREPARATION 210

17.3. FINAL WELL OPERATION REPORT STRUCTURE 21117.3.1. General Report Structure 21117.3.2. Cluster/Platform Final Well Report Structure 212

17.4. AUTHORISATION 213

17.5. ATTACHMENTS 213


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APPENDIX A - REPORT FORMS 214

A.1. INITIAL ACTIVITY REPORT (ARPO 01) 215

A.2. DAILY REPORT (ARPO 02) 216

A.3. CASING RUNNING REPORT (ARPO 03) 217

A.4. CASING RUNNING REPORT (ARPO 03B) 218

A.5. CEMENTING JOB REPORT (ARPO 04A) 219

A.6. CEMENTING JOB REPORT (ARPO 04B) 220

A.7. BIT RECORD (ARPO 05) 221

A.8. WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06) 222

A.9. WELL PROBLEM REPORT (ARPO 13) 223

APPENDIX B - ABBREVIATIONS 224

APPENDIX C - WELL DEFINITIONS 228

APPENDIX D - BIBLIOGRAPHY 230
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2. PRESSURE EVALUATION

2.1. FORECAST ON PRESSURE AND TEMPERATURE GRADIENTSA well programme must contain a technical analysis including graphs of pressure gradients(overburden, pore, fracture) and temperature gradient.

The following information must be included in the analysis:

a) Method for calculating the Overburden Gradient, if obtained from electric logs

of reference wells or from seismic analysis.

b) Method for defining the Pore Pressure Gradient, if obtained from data (RFT,

DST, BHP gauges, production tests, electric logs, Sigma logs, D exponent) ofreference wells or from seismic analysis.

c) Formula used to derive the Fracture Gradient.

d) Source used to obtain the Temperature Gradient.

The formulas normally used to calculate the Overburden Gradient are:

H28.3

1000PiPt

=

200t

47t228.1D

+

=

10

hD

Hi

10

Gov

=

where:

PiP = Numbers of second (calculated from sonic log for regularly depthinterval, i.e. every 50/100/200m)

t = Transit time (second 10-3)

D = Density of the formation

Gov = Overburden gradient

H = Formation interval with the same density D

Hi = Total depth (H)


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Equations used by ENI Agip division for fracture gradient calculation, (when overburdengradients and pore pressure gradients have been defined), are listed below:

Terzaghi equation (commonly used):

)GG(1

2GG povpf

+=

When the formation is deeply invaded with water:

)GG(2GG povpf +=

When the formation is plastic:

ovf GG =

where:

Gf = Fracture pressure

Gov = Overburden gradient

Gp = Formation pressure

v = Poissions modulus

when Poissons modulus may have the following values:

= 0.25 for clean sands, sandstone and carbonate rocks down to mediumdepth

= 0.28 for sands with shale, sandstone and carbonate rocks at great

depth.

2.2. OVERPRESSURE EVALUATION

There are three methods of qualitative and quantitative assessment of overpressure:

a) Methods before drilling

b) Methods while drilling

c) Methods after drilling.


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2.2.1. Methods Before Drilling

Gradients prediction is based, on the most part, analysis and processing of seismic data

and data obtained from potential reference wells. This includes:Drilling Records These can be used in determining hole problems, abnormal

pressures, lost circulation zones, required mud weights andproperties, etc.

Wireline Logs These can provide useful geological information such aslithology, formations tops, bed thicknesses, dips, faults, washout, lost circulation zones, formation fluid content andformation fluid pressure (pore pressure).

Seismic Surveys Provides two of the most important applications of seismicdata in; the detection of formations characterised by abnormalpressures and; in the forecasting of probable pressuregradient. The data from seismic surveys are analysed andinterpreted to evaluate transit times and propagation velocityfor each interval in the formation. Since overpressurisedzones have a porosity higher than normal, it is reflected in atravel time increase.

It is obvious that if the drilling is explorative and is the first wellin a specific area, the seismic data analysis may be the solesource of information available.

The prediction of the gradients is essential for planning the

well and must be included in the drilling programme.

This initial drilling phase may be able to detect zones ofpotential risk but cannot guarantee against the potentialpresence and magnitude of abnormal pressures and, hencecaution must be exercised.

2.2.2. Methods While Drilling

Given all the predictive methods available, successful drilling still depends on theeffectiveness of the methods adopted and on the way they are used in combination.Although most of these methods do not provide the actual overpressure picture, they dosignal the presence of an abnormal conditions due to the existence of an abnormallybehaving zone. Such methods, therefore, provide a warning that a more careful and diligentobservation must be maintained on the well.

The most critical situation occurs when a well with normal gradient penetrates a highpressure zone without any indications caused by faulting or outcropping at a higherelevation. However, when abnormal pressure occurs as a result of compaction only, many

of the following real time indicators appears before a serious problem develops.


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2.2.3. Real Time Indicators

Penetration Rate While drilling in normal pressured shales of a well, there will

be a uniform decrease in the drilling rate due to the increasein shale density. When abnormal pressure is encountered, thedensity of the shale is decreased with a resultant increase inporosity. Therefore, the drilling rate will gradually increase asthe bit enters an abnormal pressured shale. The corrected dexponent and Eni-Agip Sigmalog eliminate the effects ofdrilling parameter variations and give a representativemeasure of formation drillability.

The TDC Engineer is responsible for continuous monitoringand shall immediately report to the Company Drilling andCompletion Supervisor, if any change occurs.

A copy of corrected the d exponent or Agip Sigmalog shallbe sent on daily basis to the Companys Shore Base DrillingOffice by telefax for further checking.

Drilling Break A drilling break is defined as a rapid increase in penetrationrate after a relatively long interval of slow drilling.

Any time a drilling break is noticed, drilling shall be suspendedand a flow check carried out. If there is any lingering doubt,the hole will be circulated out until bottoms up.

Torque Torque sometimes increases when an abnormally pressured

shale section is penetrated due to the swelling of plastic claycausing a decrease in hole diameter and/or accumulation oflarge cuttings around the bit and the stabilisers.

Also torque is not easy to interpret in view of manyphenomena which can affect it (hole geometry, deviation,bottom hole assembly, etc.), it must be thought as thesecond-order parameter for diagnosing abnormal pressure.

Tight Hole During

Connections

Tight hole when making connections can indicate that anabnormal pressured shale is being penetrated with low mudweight. When this occurs it is confirmed when the hole must

be reamed several times before a connection can be made.

Hole Fill When making up connections, cavings may settle preventingthe bit returning to bottom.

Wall instability, in an area of abnormal pressure, may causesloughing. It should be noted that fill may be due to othercauses, such as wall instability through geomechanicalreasons (fracture zones), inefficient well cleaning by thedrilling mud, rheological properties of mud insufficient to keepcuttings in suspension, etc.


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MWD In addition to directional drilling data, MWD can provide a widerange of bottom hole drilling parameters and formationevaluation, e.g.: bottomhole weight on bit, torque at bit,

gamma ray, mud and formation resistivity, mud pressure andmud temperature.

If the true weight and torque at the bit are known, the drillingrate can be normalised with more accuracy by producing amore accurate d exponent and Agip Sigmalog.

Formation resistivity is plotted and interpreted for pressuredevelopment. It should also be noted that differential resistivitybetween the mud in the drill pipe and in the annular spacemay be considered as a kick indicator.

Bottomhole mud temperature can also be an indicator of overpressure as discussed below.

2.2.4. Indicators Depending on Lag Time

Mud Gas The monitoring and interpretation of gas data are fundamentalto detecting abnormally pressured zones.

Background gas is the gas released by the formation whiledrilling. It usually is a low but steady level of gas in the mudwhich may be interrupted by higher levels resulting fromthe drilling of a hydrocarbon bearing zone or from trips andconnections.

An increase in the level of background gas, from thatpreviously found in overlying normally compacted shales,often occurs when drilling undercompacted formations.

Gas shows can occur when porous, permeable formationscontaining gas are penetrated. Monitoring the form and thevolume of gas shows will make it easier to detect a state ofnegative differential pressure.

Trip gas may be an indication of well underbalance. Theequivalent density applied to the formation with pumps off(static) is lower than the equivalent circulating density(dynamic) and when the well is close to balance point, the

drop in pressure while static may allow gas to flow from theformation into the well. The quantity of gas observed at thesurface when circulation is resumed, however will dependon several factors, e.g., differential pressure, formationpermeability, drill pipe pulling speed, swabbing. Failure tofill the hole on trips may also cause an increase in trip gas.

Connection gas may be an indication of well imbalance(see above).

The progressive changes, or trend, in connection gases isan important aid to evaluate differential pressure. When anundercompacted zone of uniform shale is drilled without

increasing the mud weight, the amount of connection gaswill almost always increase.


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Mud Temperature Measurement of mud temperature can also be used to detectundercompacted zones and, under ideal conditions, or toanticipate their approach. This is because temperature

gradients observed in undercompacted series are, in general,abnormally high compared with overlying normally pressuredsequences.

Accurate interpretation of these data is very difficult, due to anumber of variables which frequently mask changes ingeothermal gradient:

Inflow temperature, which is dependent on the amount ofcooling at surface.

Flow rate, which affects the speed at which the mud, andthe calories it contains, returns up the annulus.

Thermophysical properties of the mud. Heating effects at the bit face.

Heat exchange in the marine riser between the mud andthe sea.

Halts in drilling and/or circulation.

Surface operations such as transfer of mud between pits,etc.

Cutting Analysis Lithology: the lithological sequence may provide an overallindication of the possible existence of abnormal pressure.The presence of seals, drains or thick clay sequences is a

determining factor in this analysis. Shale density: is based on the principle that bulk density in

an undercompacted zone does not follow the trend of thenormally compacted overlying clays and shales. Thevalidity of the density obtained depends on the claycomposition (the presence of accessory heavy mineralscan greatly change the density), the depth lagging (whichcan make cutting selection difficult), the mud type (reactivemuds have an adverse effect on measurement quality) andclay consolidation (difficult to measure on wellsite thedensity of clays not sufficiently consolidated).

Shale factor: undercompacted clays which have beenunable to dehydrate often have an unusually highproportion of smectite and an abnormally high shale factor.However, the initial proportions of the clay minerals in thedeposit can mask changes in shale factor and give a falsealarm.

Shape, size and volume of cuttings: the amount of shalecuttings will usually increase, along with a change in shape,when an abnormal pressure zone is penetrated.


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Cuttings from normal pressured shales are small withrounded edges and are generally flat, while cuttings froman abnormal pressure are often long and splintered with

angular edges. As the differential between the porepressure and the drilling fluid hydrostatic head is reduced,the pressured shales will burst into the wellbore rather thanhaving being drilled. This change in shape, along with anincrease in the amount of cuttings at the surface, could bean indication that abnormal pressure has beenencountered.

2.2.5. Methods After Drilling

These are methods founded on the elaboration of the data from electrical logs such as:

induction log (IES), sonic log (SL), formation density log (FDC), neutron log (NL).The most used methods for abnormal pressure detection are:

Induction Log (IES)

Method:

Is used in sand and shale formations and consists in theplotting of the shale resistivity values at relative depths on asemilog graphic (depth in decimal scale and resistivity inlogarithmical scale).

In formations, if they are normal compacted, the resistivity ofthe shales increases with depth but, in overpressure zones, itlowers with depth increase (Refer to figure .2.a).

Also it is possible to plot the values of the shale conductibility;in this case the plot will be symmetric to that described above.The method is acceptable only in shale salt water bearingformations which have sufficient and a constant level ofsalinity.

For the calculation of gradient, refer to the OverpressureEvaluation Manual.


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Figure .2.A - Induction Log

Shale Formation Factor

(Fsh) Method:

This is more sophisticated than the IES method describedabove. It eliminates the inconveniences due to water salinityvariation. It consists in the plotting of the shale factors on asemilog graph (depth in decimal scale and resistivity in

logarithmical scale)at relative depths. The Fsh is calculated

by the following formula:

w

shsh

R

RF =

Where:

Rsht =The shale resistivity read on the log in the pointswhere they are most cleaned

Rw = The formation water resistivity reported in

Schlumbergers tables on the log interpretationchart.

The value of Fsh, increases with depth in normal compactionzones and lowers in overpressure zones (Refer to figure 2.b).

For the gradients calculation, the Overpressure EvaluationManual.

Fig.1,2-1

INDUCTION LOG

1500

2000

2500

3000

3500

4000

4500

5000

1 10 100

Resistivity (OHMM)

Top

Overpresure


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Figure 2.B - F Shale

Sonic Log (SL) Method: Also termed t shale, is the most widely used as, fromexperience, it gives the most reliability. It consists in theplotting, on a semilog graph (depth in decimal scale and

transit time in logarithmical scale) of the t values (transit time)at relative depths.

The t value (transit time) is read on sonic log in the shale

points where they are cleanest; t value lowers with the depthincrease in normal compaction zones and increases with thedepth in overpressure zones (Refer to figure 2.c)

For the calculation of gradient, refer to the OverpressureEvaluation Manual.

1500

2000

2500

3000

3500

4000

4500

5000

1 10 100F shale

Depth(m

)

Top Overpresure


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Figure 2.C Sonic log

2.3. TEMPERATURE PREDICTION

The temperature at various depths to which a well is drilled must be evaluated as it has agreat influence on the properties of both the reservoir fluids and materials used in drillingoperations.

The higher temperatures encountered at increasing depth usually have adverse effectsupon materials used in drilling wells but may be beneficial in production as it lowers theviscosity of reservoir fluids allowing freer movement of the fluids through the reservoir rock.

In drilling operations the treating chemicals materials and clays used in drilling mud becomeineffective or unstable at higher temperatures and cement slurry thickening and settingtimes accelerate (also due to increasing pressure).

Another effect of temperature is the lowering of the strength and toughness of materialsused in drilling and casing operations such as drillpipe and casing.

As technology improves and wells can be drilled even deeper, these problems becomemore prevalent.

0

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1000

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2000

2500

3000

3500

4000

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10 100 1000

Depth(m

)TopOverpresure


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2.3.1. Temperature Gradients

The temperature of the rocks at a given point, formation temperature, and relationship

between temperature and depth is termed the thermal gradient. Temperature gradientsaround the world can vary from between 1oC in 110ft (35m) to 180ft (56m).

The heat source is radiated through the rock therefore it is obvious that temperaturegradients will differ throughout the various regions where there are different rocks. Seasonalvariations in surface temperatures have little effect on gradients deeper than 100ft (30m)except in permafrost regions.

It is important therefore that the local temperature gradient is determined from previousdrilling reports, offset well data or any other source. In most regions, the temperaturegradient is well known and is only affected when in the vicinity of salt domes. If thetemperature gradient is not known in a new area, it is recommended that a gradient of3

oC/100m be assumed.

The calculation of temperature at depth if the thermal gradient is known, is simply:

T = Surface Ambient Temp + Depth/Gradient (Depth per Degree Temp)

2.3.2. Temperature Logging

During the actual drilling of a well, temperature surveys will be taken at intervals which mayhelp to confirm the accuracy of the temperature prediction.

Temperature measurement during drilling may be by simple thermometer or possibly byrunning thermal logs, however, the circulation of mud or other liquids tends to smooth outthe temperature profile around the well bore and mask the distinction of the individual

strata. Consequently the use of temperature logs during drilling is uncommon.


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3. SELECTION OF CASING SEATS

The selection of casing setting depths is one of the most critical factors affecting welldesign. These are covered in detail in the Casing Design Manual. The following sectionsare to provide engineers with an outline of the criteria necessary to enable casing seatselection.

The following parameters must be carefully considered in this selection:

Total depth of well

Pore pressures

Fracture gradients

The probability of shallow gas pockets

Problem zones

Depth of potential prospects

Time limits on open hole drilling

Casing program compatibility with existing wellhead systems

Casing program compatibility with planned completion programme on productionwells

Casing availability - size, grade and weight

Economics - time consumed to drill the hole, run casing and the cost ofequipment.

When planning, all available information should be carefully documented and considered to

obtain knowledge of the various uncertainties.Information is sourced from:

Evaluation of the seismic and geological background documentation used asthe decision for drilling the well.

Drilling data from offset wells in the area. (Company wells or scoutinginformation).

The key factor to satisfactory picking of casing seats is the assessment of pore pressure(formation fluid pressures) and fracture pressures throughout the length of the well.

As the pore pressures in a formation being drilled approach the fracture pressure at the last

casing seat then installation of a further string of casing is necessary.

figure 3.b show typical examples of casing seat selections.


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Casing is set at depth 1, where pore pressure is P1 and the fracture pressure isF1.

Drilling continues to depth 2, where the pore pressure P2 has risen to almostequal the fracture pressure (F1) at the first casing seat.

Another casing string is therefore set at this depth, with fracture pressure (F2).

Drilling can thus continue to depth 3, where pore pressure P3 is almost equal tothe fracture pressure F2 at the previous casing seat.

This example does not include any safety or trip margins, which would, in practice, be takeninto account.

Figure 3.A - Example of idealised Casing Seat Selection


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Figure 3.B - Example Casing Seat Selection

(for a typical geopressurised well using a pressure profile).


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3.1. CONDUCTOR CASING

The setting depth for conductor casing is usually shallow and selected so that drilling fluid

may be circulated to the mud pits while drilling the surface hole. The casing seat must be inan impermeable formation with sufficient fracturing resistance to allow fluid circulation to thesurface. In wells with subsea wellheads, no attempt is made to circulate through theconductor string to the surface but must be set deep enough to assist in stabilising thesubsea guide base to which guide lines are attached.

The driving depth of the conductor pipe is established with the following formula:

Hi = [df x (E+H) - 103 x H]/[1.03 - df + 0.67 x (GOVhi - 1.03)]

where:

Hi = Minimum driving depth (m) from seabed

E = Elevation (m) distance from bell nipple and sea level

H = Water depth (m)

df = Maximum mud weight (kg/l) to be used

GOVhi = integrated density of sediments (kg/dm3/10m)

3.2. SURFACE CASING

The setting depth of surface casing should be in an impermeable section below fresh waterformations. In some instances, where there is near surface gravel or shallow gas, it mayneed to be cased off shallower.

The depth should be enough to provide a fracture gradient sufficient to allow drilling to the

next casing setting point and to provide reasonable assurance that broaching to the surfacewill not occur in the event of BOP closure to contain a kick.

3.3. INTERMEDIATE CASING

The most predominant use of intermediate casing is to protect normally pressuredformations from the effects of increased mud weight needed in deeper drilling operations.An intermediate string may be necessary to case off lost circulation, salt beds, or sloughingshales.

In cases of pressure reversals with depth, intermediate casing may be set to allow reductionof mud weight.

When a transition zone is penetrated and mud weight increased, the normal pressure

interval below surface pipe is subjected to two detrimental effects:

The fracture gradient may be exceeded by the mud gradient, particularly if itbecomes necessary to close-in on a kick The result is loss of circulation and thepossibility of an underground blow-out occurring.

The differential between mud column pressure and formation pressure isincreased, increasing the risk of stuck pipe.

However, in general practice, drilling is allowed until the mud weight is within 50gr/l of thefracture gradient measured by conducting a leak-off test at the previous casing shoe.

Attempts to drill with mud weight higher than this limit are sometimes successful, but manyholes have been lost by attempts to extend the intermediate string setting depth beyondthat indicated by the above rule.


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This can cause either, kicks causing loss of circulation and possibly an underground blow-out or the pipe becomes differentially stuck. Sloughing of high pressure zones can alsocause stuck pipe .

Significantly in soft rock areas, the fracture gradient increases relatively slowly compared tothe depth of the surface casing string, but the pressure gradients in the transition zonesusually change rapidly.

Emphasis is often placed on setting the surface casing to where there is an acceptablefracture gradient. Greater control over potential conditions at the surfaces casing seat isaffected by the intermediate casing setting depth decision.

It is often tempting to drill a little deeper without setting pipe in exploratory wells. Whenpressure gradients are not increasing this can be a reasonably acceptable decision, but,with increasing gradient, the risk is greater and should be carefully evaluated.

To ensure the integrity of the surface casing seat, leak-off tests should be specified in theDrilling Programme.

3.4. DRILLING LINER

The setting of a drilling liner is often an economically attractive decision in deep wells asopposed to setting a full string. Such a decision must be carefully considered as theintermediate string must be designed for burst as if it were set to the depth of the liner.

If drilling is to be continued below the drilling liner then burst requirements for theintermediate string are further increased. This increases the cost of the intermediate string.Also, there is the possibility of continuing wear of the intermediate string that must beevaluated.

If a production liner is planned then either the production liner or the drilling liner should betied back to the surface as a production casing.

If the drilling liner is to be tied-back, it is usually better to do so before drilling the hole forthe production liner. By doing so, the intermediate casing can be designed for a lower burstrequirement, resulting in considerable cost savings. Also, any wear to the intermediatestring is spanned prior to drilling the producing interval.

If increased mud weight will be required while drilling hole for the drilling liner, then leak-offtests should be specified in the Drilling Procedures in the programme for the intermediatecasing shoe.

Insufficient fracture gradient at the shoe may limit the depth of the drilling liner.

3.5. PRODUCTION CASING

Whether production casing or a liner is installed, the depth is determined by the geologicalobjective. Depths, hence the casing programme, may have to be altered accordingly ifdepths run high or low.

The objective and method of identifying the correct depth should also be stated in theprogramme.


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4. CASING DESIGN

4.1. INTRODUCTIONFor detailed casing design criteria and guidelines, refer to the Casing Design Manual.

The selection of casing grades and weights is an engineering task affected by manyfactors, including local geology, formation pressures, hole depth, formation temperature,logistics and various mechanical factors.

The engineer must keep in mind during the design process the major logistics problems incontrolling the handling of the various mixtures of grades and weights by rig personnelwithout risk of installing the wrong grade and weight of casing in a particular hole section.Experience has shown that the use of two to three different grades or two to three differentweights is the maximum that can be handled by most rigs and rig crews.

After selecting a casing for a particular hole section, the designer should considerupgrading the casing in cases where:

Extreme wear is expected from drilling equipment used to drill the next holesection or from wear caused by wireline equipment.

Buckling in deep and hot wells.

Once the factors are considered, casing cost should be considered.

If the number of different grades and weights are necessary, it follows that cost is notalways a major criterion.

Most major operating companies have differing policies and guidelines for the design ofcasing for exploration and development wells, e.g.:

For exploration, the current practice is to upgrade the selected casing,irrespective of any cost factor.

For development wells, the practice is also to upgrade the selected casing,irrespective of any cost factor.

For development wells, the practice is to use the highest measured bottomholeflowing pressures and well head shut-in pressures as the limiting factors forinternal pressures expected in the wellbore. These pressures will obviouslyplace controls only on the design of production casing or the production liner,and intermediate casing.

The practice in design of surface casing is to base it on the maximum mud weights used todrill adjacent development wells.

Downgrading of a casing is only carried out after several wells are drilled in a given areaand sufficient pressure data are obtained.


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4.2. PROFILES AND DRILLING SCENARIOS

4.2.1. Casing Profiles

The following are the various casing configurations which can be used on onshore andoffshore wells.

Onshore

Drive/structural/conductor casing

Surface casing

Intermediate casings

Production casing

Intermediate casing and drilling liners

Intermediate casing and production liner

Drilling liner and tie-back string.

Offshore - Surface Wellhead

As in onshore above.

Offshore - Surface Wellhead & Mudline Suspension


Surface casing and landing string

Intermediate casings and landing strings

Production casing Intermediate casings and drilling liners


Offshore - Subsea Wellhead


Surface casing

Intermediate casings

Production casing

Intermediate casing and drilling liners Intermediate casing and production liner


Refer to the following sections for descriptions of the casings listed above.


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4.3. CASING SPECIFICATION AND CLASSIFICATION

There is a great range of casings available from suppliers from plain carbon steel for

everyday mild service through exotic duplex steels for extremely sour service conditions.The casings available can be classified under two specifications, API and non-API.

Casing specifications, including API and its history, are described and discussed in theCasing Design Manual. Sections 4.3.1 and 4.3.2 below give an overview of someimportant casing issues.

Non-API casing manufacturers have produced products to satisfy a demand in the industryfor casing to meet with extreme conditions which the API specifications do not meet. Thearea of use for this casing are also discussed in section 4.3.1 below and the productsavailable described in section 4.3.2.

4.3.1. Casing Specification

It is essential that design engineers are aware of any changes made to the APIspecifications. All involved with casing design must have immediate access to the latestcopy of API Bulletin 5C2 which lists the performance properties of casing, tubing anddrillpipe. Although these are also published in many contractors' handbooks and tables,which are convenient for field use, care must be taken to ensure that they are current.

Operational departments should also have a library of the other relevant API publications,and design engineers should make themselves familiar with these documents and theircontents.

It should not be interpreted from the above that only API tubulars and connections may beused in the field as some particular engineering problems are overcome by specialistsolutions which are not yet addressed by API specifications. In fact, it would be impossibleto drill many extremely deep wells without recourse to the use of pipe manufactured outwithAPI specifications (non-API).

Similarly, many of the Premium couplings that are used in high pressure high GORconditions are also non-API.

When using non-API pipe, the designer must check the methods by which the strengthshave been calculated. Usually it will be found that the manufacturer will have used thepublished API formulae (Bulletin 5C3), backed up by tests to prove the performance of hisproduct conforms to, or exceeds, these specifications. However. in some cases, themanufacturers have claimed their performance is considerably better than that calculated by

the using API formulae. When this occurs the manufacturers claims must be criticallyexamined by the designer or his technical advisors, and the performance corrected ifnecessary.

It is also important to understand that to increase competition. the API tolerances have beenset fairly wide. However, the API does provide for the purchaser to specify more rigorouschemical, physical and testing requirements on orders, and may also request placeindependent inspectors to quality control the product in the plant.


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4.3.2. Classification Of API Casing

Casing is usually classified by:

Outside diameter Nominal unit weight

Grade of the steel

Type of connection

Length by range

Manufacturing process.

Reference should always be made to current API specification 5C2 for casing lists andperformances.

4.4. MECHANICAL PROPERTIES OF STEEL

4.4.1. General

Failure of a material or of a structural part may occur by fracture (e.g. the shattering ofglass), yield, wear, corrosion, and other causes. These failures are failures of the material.Buckling may cause failure of the part without any failure of the material.

As load is applied, deformation takes place before any final fracture occurs. With all solidmaterials, some deformation may be sustained without permanent deformation, i.e. thematerial behaves elastically.

Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of

plastic, or permanent, deformation, If a material sustains large amounts of plasticdeformation before final fracture. It is classed as ductile material, and if fracture occurs withlittle or no plastic deformation. The material is classed as brittle.

4.4.2. Stress-Strain Diagram

Tests of material performance may be conducted in many different ways, such as bytorsion, compression and shear, but the tension test is the most common and is qualitativelycharacteristics of all the other types of tests.

The action of a material under the gradually increasing extension of the tension test isusually represented by plotting apparent stress (the total load divided by the original cross-

sectional area of the test piece) as ordinates against the apparent strain (elongationbetween two gauge points marked on the test piece divided by the original gauge length) asabscissae.

A typical curve for steel is shown in figure 4.a.

From this, it is seen that the elastic deformation is approximately a straight line as called forby Hooke's law, and the slope of this line, or the ratio of stress to strain within the elasticrange, is the modulus of elasticity E, sometimes called Young's modulus.

Beyond the elastic limit, permanent, or plastic strain occurs.

If the stress is released in the region between the elastic limit and the yield strength (seeabove) the material will contract along a line generally nearly straight and parallel to the

original elastic line, leaving a permanent set.


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Figure 4.A- Stress - Strain Diagram

In steels, a curious phenomenon occurs after the end of the elastic limit, known as yielding.This gives rise to a dip in the general curve followed by a period of deformation atapproximately constant load. The maximum stress reached in this region is called the upperyield point and the lower part of the yielding region the lower yield point. In the harder andstronger steels, and under certain conditions of temperature, the yielding phenomenon isless prominent and is correspondingly harder to measure. In materials that do not exhibit amarked yield point, it is customary to define a yield strength. This is arbitrarily defined as the

stress at which the material has a specified permanent set (the value of 0.2% is widelyaccepted in the industry).

For steels used in the manufacturing of tubular goods the API specifies the yield strength asthe tensile strength required to produce a total elongation of 0.5% and 0.6% of the gaugelength.

Similar arbitrary rules are followed with regard to the elastic limit in commercial practice.Instead of determining the stress up to which there is no permanent set, as required bydefinition, it is customary to designate the end of the straight portion of the curve (bydefinition the proportional limit) as the elastic limit. Careful practice qualifies this bydesignating it the proportional elastic limit.


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As extension continues beyond yielding, the material becomes stronger causing a rise ofthe curve, but at the same time the cross-sectional area of the specimen becomes less as itis drawn out. This loss of area weakens the specimen so that the curve reaches a maximum

and then falls off until final fracture occurs.

The stress at the maximum point is called the tensile strength (TS) or the ultimate strengthof the material and is its most often quoted property.

The mechanical and chemical properties of casing, tubing and drill pipe are laid down in APIspecifications 5CT and 5C2.

Depending on the type or grade, minimum requirements are laid down for the mechanicalproperties, and in the case of the yield point even maximum requirements (except for H 40).

The denominations of the different grades are based on the minimum yield strength, e.g.:

Grade Min. Yield Strength

H 40 40,000psi

J 55 55,000psi

C 75 75,000psi

N 80 80,000psi

etc.

In the design of casing and tubing strings the minimum yield strength of the steel is taken asthe basis of all strength calculations

As far as chemical properties are concerned, in API 5CT only the maximum phosphorus

and sulphur contents are specified, the quality and the quantities of other alloying elementsare left to the manufacturer.

API specification 5CT Restricted yield strength casing and tubing however specifies, thecomplete chemical requirements for grades C 75, C 95 and L 80.

4.5. NON-API CASING

Eni-Agip Division and Affiliates policy is to use API casings whenever possible. Somemanufacturers produce non-API casings for H2S and deep well service where API casingsdo not meet requirements. The most common non-API grades are shown in the CasingDesign Manual (STAP-P-1-M-6110-4.3).

Reference to API and non-API materials should be made to suit the environment in whichthey are recommended to be employed.


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4.6. CONNECTIONS

The selection of a casing connection is dependant upon whether the casing is exposed to

wellbore fluids and pressures. API connections are normally used on all surface andintermediate casing and drilling liners. Non-API or premium connections are generally usedon production casing and production liners in producing wells.

API connections rely on thread compound to form the seal and are not recommended forsealing over long periods of time when exposed to well high pressures and corrosive fluidsas the compound can be extruded exposing the threads to corrosive fluids which in turnreduces the strength of the connection. Sealing on premium connections are provided by atleast one metal-to-metal seal which prevents this exposure of the threads to corrosiveelements, hence, retains full strength.

The properties of both API and non-API connections are described below.

4.6.1. API Connections

The types of API connections available are:

Round thread short which is coupled.

Round thread long which is coupled.

Buttress thread which is coupled, with both normal and special clearance.

Extreme line thread which is integral with either normal or special clearance.

Round thread couplings, short or long, have less strength than the corresponding pipebody. This in turn requires heavier pipe to meet design requirements, than if the pipe and

coupling had the same strength. Problems like pullouts or jump-outs can happen withround thread type coupling on 103/4" casing or when also subjected to bending stresses, i.e.

doglegs, directional drilled holes. etc.

Buttress threads have, according to API calculations, higher joint strength than the pipebody yield strength with a few exceptions. Buttress threads also stab and enter easier thanround threads, therefore, should be used whenever possible, except for 20" and larger pipewhere special connections could be beneficial due to having superior make-upcharacteristics.

API round threads and buttress threads have no metal to metal seals. As stated earlier, theseal in API thread is created by the thread compound which contains metal which fill thevoid space between the threads. When subjected to high pressure gas, temperature

variations, and/or corrosive environment this sealing method may fail. Therefore, in suchconditions, connections with metal-to-metal seals, should be utilised.

According to API standards the coupling shall be of the same grade as the pipe exceptgrade H 40 and J 55 which may be furnished with grade J 55 or K 55 couplings.

For connection dimensions refer to the current API specification.


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4.7. APPROACH TO CASING DESIGN

Casing design is basically a stress analysis procedure which is fully described in the Casing

Design Manual.As there is little point in designing for loads that are not encountered in the field, or inhaving a casing that is disproportionally strong in relating to the underlying formations, thereare clearly four major elements to casing design:

Definition of the loading conditions likely to be encountered throughout the life ofthe well.

Specification of the mechanical strength of the pipe.

Estimation of the formation strength using rock and soil mechanics.

Estimation of the extent to which the pipe will deteriorate through time andquantification of the impact that this will have on its strength.

4.7.1. Wellbore Forces

Various wellbore forces affect casing design. Besides the three basic conditions (burst,collapse and axial loads or tension), these include:

Buckling.

Wellbore confining stress.

Thermal and dynamic stress.

Changing internal pressure caused by production or stimulation.

Changing external pressure caused by plastic formation creep.

Subsidence effects and the effect of bending in crooked hole. Various types of wear caused by mechanical friction.

H2S or squeeze/acid operations.

Improper handling and make-up.

This list is by no means comprehensive because new research is still in progress.

The steps in the design process are:

1) Consider the loading for burst first, since burst will dictate the design for most of thestring.

2) Next, the collapse load should be evaluated and the string sections upgraded ifnecessary.

3) Once the weights, grades and section lengths have been determined to satisfy theburst and collapse loading, the tension load can then be evaluated.

4) The pipe can be upgraded as necessary as the loads are found and the coupling typedetermined.

5) The final step is a check on biaxial reductions in burst strength and collapseresistance caused by compression and tension loads, respectively. If these reductionsshow the strength of any part of the section to be less than the potential load, thesection should again be upgraded.


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4.7.2. Design Factor (DF)

The design process can only be completed if knowledge of all anticipated forces is

available. This however, is idealistic and never actually occurs. Some determinations areusually necessary and some degree of risk has to be accepted.

The risk is usually due to the assumed values and therefore the accuracy of the designfactors used.

Design factors are necessary to cater for:

Uncertainties in the determination of actual loads that the casing needs towithstand and the existence of any stress concentrations, due to dynamic loadsor particular well conditions.

Reliability of listed properties of the various steels used and the uncertainty inthe determination of the spread between ultimate strength and yield strength.

Probability of the casing needing to bear the maximum load provided in thecalculations.

Uncertainties regarding collapse pressure formulas.

Possible damage to casing during transport and storage.

Damage to the steel from slips, wrenches or inner defects due to cracks, pitting,etc.

Rotational wear by the drill string while drilling.

The DF will vary with the capability of the steel to resist damage from the handling andrunning equipment.

The value selected as the DF is a compromise between margin and cost.

The use of excessively high design factors guarantees against failure, but provideexcessive strength and, hence, cost.

The use of low design factors requires accurate knowledge about the loads to be imposedon the casing.

Casing is generally designed to withstand stress which, in practice, it seldom encountersdue to the assumptions used in calculations, whereas, production tubing has to bearpressures and tensions which are known with considerable accuracy.

Also casing is installed and cemented in place whereas tubing is often pulled and re-used.

As a consequence a of this and due to the fact that tubing has to combat corrosion effectsfrom formation fluid, a higher DF is used for tubing than casing.


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4.7.3. Design Factors

The following DFs must be used in casing design calculations:

Casing Grade Design Factor H 40 1.05

J 55 1.05

K 55 1.05

C 75 1.10

Burst L 80 1.10

N 80 1.10

C 90 1.10

C 95 1.10

P 110 1.10

Q 125 1.20

Collapse All Grades 1.10

< C-95 1.70

Tension > C-95 1.80

Note The tensile DF must be considerably higher than the previous factors to avoid

exceeding the elastic limit and, therefore invalidating the criteria on which burst

and collapse resistance are calculated.

4.7.4. Application of Design Factors

The minimum performance properties of tubing and casing from the API bulletin are onlyused to determine the chosen casing is within the DF.

Burst For the chosen casing (diameter, grade, weight and thread)take the lowest value from API casing tables columns 13-19.This value divided by DF gives the internal pressureresistance of casing to be used for design calculation

Collapse Use only column 11 of API casing tables and divide by the DFto obtain the collapse resistance for design calculation.

Tension Use the lowest value from columns 20-27 of the API casingtables and divide by the DF to obtain the joint strength fordesign calculation.

Note: It should be recognised that the Design Factor used in the context of

casing string design is essentially different from the Safety Factor used

in many other engineering applications.

The term Safety Factor as used in tubing design, implies that the actual physical propertiesand loading conditions are exactly known and that a specific margin is being allowed forsafety. The loading conditions are not always precisely known in casing design, andtherefore in the context of casing design the term Safety Factor should be avoided.


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4.8. DESIGN CRITERIA

4.8.1. Burst

Burst loading on the casing is induced when internal pressure exceeds external pressure.

To evaluate the burst loading, surface and bottomhole casing burst resistance must first beestablished according to the company procedure outlined below.

Surface Casing

Internal Pressure The wellhead burst pressure limit is arbitrary, and is generally set equal tothat of the working pressure rating of the wellhead and BOP equipmentbut with a minimum of 140kg/cm

2. See BOP selection criteria in section

9.1.

With a subsea wellhead, the wellhead burst pressure limit is taken as 60%

of the value obtained as the difference between the fracture pressure atthe casing shoe and the pressure of a gas column to surface but in anycase not less than 2,000psi (140atm).

Consideration should be given to the pressure rating of the wellhead andBOP equipment which must always be equal to, or higher than, thepressure rating of the pipe.

When an oversize BOP having a capacity greater than that necessary is

selected, the wellhead burst pressure limit will be 60% of the calculated

surface pressure obtained as difference between the fracture pressure atthe casing shoe with a gas column to surface. Methane gas (CH4) withdensity of 0.3kg/dm

3is normally used for this calculation. In any case it

shall never be considered less than 2,000psi (140atm).

The use of methane for this calculation is the worst case when thespecific gravity of gas is unknown, as the specific gravities of any gaseswhich may be encountered will usually be greater than that of methane.

The bottomhole burst pressure limit is set equal to the predicted fracturegradient of the formation below the casing shoe.

Connect the wellhead and bottomhole burst pressure limits with a straightline to obtain the maximum internal burst load verses depth.

When taking a gas kick, the pressure from bottom-hole to surface willassume different profiles according to the position of influx into thewellbore. The plotted pressure versus depth will produce a curve.

External Pressure In wells with surface wellheads, the external pressure is assumed to beequal to the hydrostatic pressure of a column of drilling mud.

In wells with subsea wellheads:

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm)

At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm)

Net Pressure The resultant load, or net pressure, will be obtained by subtracting, at

each depth, the external from internal pressure.


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Intermediate Casing

Internal Pressure The wellhead burst pressure limit is taken as 60% of the calculated value

obtained as difference between the fracture pressure at the casing shoeand the pressure of a gas column to wellhead.

In subsea wellheads, the wellhead burst pressure limit is taken as 60% ofthe value obtained as the difference between the fracture pressure at thecasing shoe and the pressure of a gas column to the wellhead minus theseawater pressure

The bottom-hole burst pressure limit is equal to that of the predictedfracture gradient of the formation below the casing shoe.

Connect the wellhead and bottom-hole burst pressure limits with a

straight line to obtain the maximum internal burst pressure

External Pressure The external collapse pressure is taken to be equal to that of theformation pressure.

With a subsea wellhead, at the wellhead, hydrostatic seawater pressureshould be considered.

Net Burst Pressure The resultant burst pressure is obtained by subtracting the external frominternal pressure versus depth.


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Production Casing

The worst case burst load condition on production casing occurs when a well is shut-in and thereis a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied to the top ofthe packer fluid (i.e. completion fluid) in the tubing-casing annulus.

Internal Pressure The wellhead burst limit is obtained as the difference between thepore pressure of the reservoir fluid and the hydrostatic pressureproduced by a colum of fluid which is usually gas (density =0.3kg/dm

3).

Actual gas/oil gradients can be used if information on these areknown and available.

The bottom-hole pressure burst limit is obtained by adding the

wellhead pressure burst limit to the annulus hydrostatic pressureexerted by the completion fluid.

Generally the completion fluid density is, equal to or close to, themud weight in which casing is installed.

Note: It is usually assumed that the completion fluid and

mud on the outside of the casing remains

homogeneous and retain their original density

values. However this is not actually the case

particularly with heavy fluids but it is also assumed

that the two fluids will degrade similarly under thesame conditions of pressure and temperature.

Connect the wellhead and bottom-hole burst pressure limits with astraight line to obtain the maximum internal burst pressure.

Note: If it is foreseen of that stimulation or hydraulic

fracturing operations may be necessary in future,

therefore the fracture pressure at perforation depth

and at the well head pressure minus the hydrostatic

head in the casing plus a safety margin of 70kg/cm2

(1,000psi) will be assumed.

External Pressure The external pressure is taken to be equal to that of the formationpressure.

With a subsea wellhead, at the wellhead, hydrostatic seawaterpressure should be considered.

Net Burst Pressure The resultant burst pressure is obtained by subtracting the externalfrom internal pressure at each depth.


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Intermediate Casing and Liner

If a drilling liner is to be used in the drilling of a well, the casing above where the liner issuspended must withstand the burst pressure that may occur while drilling below the liner. Thedesign of the intermediate casing string is, therefore, altered slightly.

Since the fracture pressure and mud weight may be greater or lowerbelow the liner shoe than casing shoe, these values must be usedto design the intermediate casing string as well as the liner.

When well testing or producing through a liner, the casing above theliner is part of the production string and must be designed accordingto this criteria

Tie-Back String

In a high pressure well, the intermediate casing string above a liner may be unable to withstand atubing leak at surface pressures according to the production burst criteria. The solution to thisproblem is to run and tie-back a string of casing from the liner top to surface, isolating theintermediate casing.

4.8.2. Collapse

Pipe collapse will occur if the external force on a pipe exceeds the combination of theinternal force plus the collapse resistance.

The reduced collapse resistance under biaxial stress (tension/collapse) should beconsidered.

No allowance is given to increased collapse resistance due to cementing.

Surface Casing

Internal Pressure For wells with a surface wellhead, the casing is assumed to becompletely empty.

In offshore wells with subsea wellheads, the internal pressureassumes that the mud level drops due to a thief zone

External Pressure In wells with a surface wellhead, the external pressure is assumed

to be equal to that of the hydrostatic pressure of a column of drillingmud.

In offshore wells with a subsea wellhead, it is calculated:

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm).

At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (ifatm).

Net Collapse Pressure The resultant collapse pressure is obtained by subtracting theinternal pressure from external pressure at each depth.


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Intermediate Casing

Internal Pressure The worst case collapse loading occurs when a loss of circulationis encountered while drilling the next hole section with the maximumallowable mud weight. This would result in the mud level inside thecasing dropping to an equilibrium level where the mud hydrostatic

equals the pore pressure of the thief zone (Refer to Errore.

L'origine riferimento non stata trovata.). Consequently it will be

assumed the casing is empty to the height (H) calculated as follows:

(Hloss-H) x dm = Hloss x Gp

H = Hloss (dm - Gp)/dm

If Gp = 1.03 (kg/cm2/10m)

Then H = Hloss (dm-1.03)/dm

Hloss = Depth at which circulation loss is expected (m)

dm = Mud density expected at Hloss (kg/dm2)

Gp = Pore pressure of thief zone (kg/cm2/10m) - usually

Normally pressured with 1.03 as gradient.

When thief zones cannot be confirmed, or otherwise, during thecollapse design, as is the case in exploration wells, Eni-Agipdivision and associates suggests that on wells with surfacewellheads, the casing is assumed to be half empty and theremaining part of the casing full of the heaviest mud planned to drillthe next section below the shoe.

In wells with subsea wellheads, the mud level inside the casing isassumed to drop to an equilibrium level where the mud hydrostaticpressure equals the pore pressure of the thief zone.

External Pressure The pressure acting on the outside of casing is the pressure of mudin which casing is installed.

The uniform external pressure exerted by salt on the casing orcement sheath through overburden pressure, should be given avalue equal to the true vertical depth of the relative point.

Net Collapse Pressure The effective collapse line is obtained by subtracting the internalpressure from external at each depth.

Production Casing

Internal Pressure During the productive life of well, tubing leaks often occur. Alsowells may be on artificial lift, or have plugged perforations or verylow internal pressure values and, under these circumstances, theproduction casing string could be partially or completely empty. Theideal solution is to design for zero pressure inside the casing whichprovides full safety, nevertheless in particular well situations, theDrilling and Completions Manager may consider that the lowestcasing internal pressure is the level of a column of the lightestdensity producible formation fluid.


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External Pressure Assume the hydrostatic pressure exerted by the mud in whichcasing is installed.

The uniform external pressure exerted by salt on the casing orcement sheath through overburden pressure, should be given avalue equal to the true vertical depth of the relative point.

Net Collapse Pressure In this case of the casing being empty, the net pressure is equal tothe external pressure at each depth.

In other cases it will be the difference between external and internalpressures at each depth.

Intermediate Casing and Liner

If a drilling liner is to be used in the drilling of a well, the casingabove where the liner is suspended must withstand the collapse

pressure that may occur while drilling below the liner.

When well testing or producing through a liner, the casing abovethe liner is part of the production casing/liner and must be designedaccording to this criteria.

Tie-Back String

If the intermediate string above the liner is unable to withstand thecollapse pressure calculated according to production collapsecriteria, it will be necessary run and tie-back a string of casing fromthe liner top to surface.

Figure 4.B - Fluid Height Calculation


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4.8.3. Tension

Note: The amount of parameters which can affect tensile loading means theestimates for the tensile forces are more uncertain than the estimates for

either burst and collapse. The DF imposed is therefore much larger.

To evaluate the tensile loading, the company procedure outlined below applies.

Surface Casing

Tension Calculate the casing string weight in air.

Calculate the casing string weight in mud multiplying the previousweight by the buoyancy factor (BF) in accordance with the mudweight in use.

Add the additional load due to bumping the cement plug to thecasing string weight in mud.

Note: This pull load is calculated by multiplying the

expected bump-plug pressure by the inside area of

the casing.

A calculation of this kind is an approximation because theassumption has been made that:

No buoyancy changes occur during cementing.

The pressure is applied only at the bottom and not where thereare changes in section. As seen with the previous case, thedifferences in the calculated values are quite small, whichjustifies the preference for the simpler approximation method.

Once the magnitude and location of the forces are determined, thetotal tensile load line may be constructed graphically. Note: morethan one section of the casing string may be loaded in compression.


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4.9. BIAXIAL STRESS

When the entire casing string has been designed for burst, collapse and tension, and the

weights, grades, section lengths and coupling types are known, reduction in burstresistance needs to be applied due to biaxial loading.

The total tensile load, which is tensile loading versus depth, is used to evaluate the effect ofbiaxial loading and can be shown graphically.

By noting the magnitude of tension (plus) or compression (minus) loads at the top andbottom of each section length of casing, the strength reductions can be calculated using theHolmquist & Nadai ellipse, see figure 4.c.

Note: The effects of axial stress on burst resistance are negligible for the

majority of wells.

4.9.1. Effects On Collapse Resistance

The collapse strength of casing is seriously affected by axial load, but the correctionadopted by the API (API Bulletin 5C3) is only valid for D/t ratios of about 15 or less. Inprinciple collapse resistance is reduced or increased when subjected to axial tension orcompression loading.

As can be seen from figure 4.c, increasing tension reduces collapse resistance where iteventually reaches zero under full tensile yield stress.

The adverse effects of tension on collapse resistance usually affects the upper portion of acasing string which is under tension reducing the collapse resistance of the pipe.

After these calculations, the upper section of casing string may need to be upgraded.

Note: Fortunately most times, the biaxial effects of axial stress on collapse

resistance are insignificant.


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Figure 4.C - Ellipse of Biaxial Yield Stress


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4.9.2. Company Design Procedure

The value for the percentage reduction of rated collapse strength is determined as follows:

1) Determine the total tensile load.

2) Calculate the ratio (X) of the actual applied stress to yield strength of the casing.

3) Refer to figure 4.d and curve effect of tension on collapse resistance and find thecorresponding percentage collapse rating (Y).

4) Multiply the collapse resistance by the percentage (Y), without tensile loads to obtainthe reduced collapse resistance value.

This is the collapse pressure which the casing can withstand at the top of the string.

The collapse resistance increases towards the bottom as the tension decreases.

Figure 4.D - Effect Of Tension On Collapse Resistance

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1

X= Tensile load

Pipe body yield strength

Y=

Co

llapsresistencewithtensileloa

d

Collapseresistencewithouttensileloa


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4.9.3. Example Collapse Calculation

Determine the collapse resistance of 7", N 80, 32lbs/ft (4kg/m), BTR casing with the shoe at

a depth of 5,750m and a mud weight of 1.1kg/dm

3

.Collapse resistance without tensile load = 8,610psi (605 kg/cm

2)

Pipe body yield strength = 745,000lbs (338 t)

Buoyancy factor = 0.859

Weight in air of casing = t274000,1

62.47x750,5=

Weight in mud of casing = 274 x 0.859 = 235 t

695.0338

235

StrengthBody YieldPipe

casingofmudinWeightx ===

From the curve or stress curve factors in figure 4.d if X = 0.695 then Y = 0.445 and thecollapse resistance with tensile load can be determined

Collapse resistance under load = Nominal Collapse Rating x 0.445


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4.10. BENDING

4.10.1. General

When calculating tension loading, the effect of bending should be considered if applicable.

The bending of the pipe causes additional stress in the walls of the pipe. This bendingcauses tension on the outside of the pipe and in compression on the inside of the bend,assuming the pipe is not already under tension (Refer to figure 4.e)

Figure 4.E - Bending Stress

Bending is caused by any deviations in the wellbore resulting from side-tracks, build-upsand drop-offs.

Since bending load increases the total tensile load, it must be deducted from the usablerated tensile strength of the pipe.

4.10.2. Determination Of Bending Effect

For determination of the effect of bending, the following formula should be used:

AfD52.15B =

where:

= Rate (degrees 30m)

D = Outside diameter of casing (ins)

Af = Cross-section area of casing (cm2)

TB = Additional tension (kg)


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The formula is obtained from the two following equations:

J2

DMB

=

where:

MB = Bending moment (MB = E x J/R) (Kg x cm)

D = Outside diameter of casing (cm)

J = Inertia moment (cm4)

= Bending stress (kg/cm2)

E x J = Bending stiffness (kg x cm2)

R = Radius of curvature (cm)

JE

LMB

=

where:

MB = Bending moment (kg x cm)

L = Arch length (cm)

E = Modulus of elasticity (kg/cm2)

J = Inertia moment (cm4)

= Change in angle of deviation (radians)

ObtainingL

JEMB

= thus the equation becomes:

L2

DE

=


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Then, by using the more current units giving the build-up or drop-off angles in degrees/30m, we obtain the final form of the equation for TB as follows:

AfTB=

L2

AfDETB

=

=

30180R

R

1L =

302180

AfDETB

=

E = 21,000kg/mm2

= 2.1 x 106kg/cm2

( ) ( )10030

AfD425

1802

101.2TB

6

=

TB = 15.52 x x D x Af

when:

Af = Square inches = Degrees/100ft

TB = 218 x x D x Af (lbs) or 63 x x D x W(lbs)

W = Casing weight (lbs/ft)

Note: Since most casing has a relatively narrow range of wall thickness (from

0.25 to 0.60), the weight of casing is approximately proportional to its

diameter. This means the value of the bending load increases with the

square of the pipe diameter for any given value of build-up/drop-off rate.

At the same time, joint tension strength rises a little less than the direct

ratio. The result is that bending is a much more severe problem with large

diameter casing than with smaller sizes.

4.10.3. Company Design Procedure

Since bending load, in effect, increases tensile load at the point applied, it must bededucted from the usable strength rating of each section of pipe that passes the point ofbending.

The section which is ultimately set through a bend must have the bending load deductedfrom its usable strength up to the top of the bend. From that point up to the top of thesection the full usable strength can be used.


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Figure 4.F - Bending Load Example


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4.11. CASING WEAR

4.11.1. General

Casing wear decreases the performance properties of casing. The burst and collapseresistance of worn casing is in direct proportion to its remaining wall thickness.

Figure 4.G - Casing Wear


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A major contributing factor to reducing the life of a casing string is poor handling throughoutthe supply chain. All personnel in this chain must adopt the proper handling procedures.

The major factors affecting casing wear are: Rotary speed

Tool joint lateral load and diameter

Drilling rate

Inclination of the hole

Severity of dog legs

Wear factor.

The location and magnitude of volumetric wear in the casing string can be estimated bycalculating the energy imparted from the rotating tool joints to the casing at different casing

points and dividing this by the amount of energy required to wear away a unit volume of thecasing. The percentage casing wear at each point along the casing is then calculated fromthe volumetric wear.

Eni-Agip acceptable casing wear limit is


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The frictional energy imparted to the casing by the rotating tool joint equals:

Energy Input Per Foot = Friction Force Per Foot x Sliding Distance

where:

Friction Force Per Foot = Friction Factor x Tool Joint Lateral Load Per Foot

Sliding Distance = n x TJ Diameter x Rotary Speed x Contact Time

and:

Tool Joint Contact TimeDPJL

TJLS =

where:

S = Drilling Distance

TJL = Tool Jo

Drilling Design Manual

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