Substation Reliability and Economic Analysis - Tractebel Choctaw Project

H. Rickel; K. Koutlev, Member, IEEE; Robert Reymers, Member, IEEE; L. Tang, Member, IEEE; L. Willis, Fellow Member, IEEE

Abstract - Recent trends are making the AIS (air insulated switchgear) vs. GIS (gas insulated switchgear) decision quite a bit more complicated than it was only a couple of years ago. Tractebel Power Company together with ABB Inc. deployed a unique analytical method to arrive at the decision to deploy a 500 kV Gas Insulated Substation near Ackerman, Mississippi, and to optimize its economic life cycle cost. The switchyard is being constructed to interconnect three generators and one transmission line at Tractebel's new 650 MW combined cycle power plant, The Choctaw Gas Generation Project. This analysis accounted for all the key life cycle costs critical to any power producer, and utilized the latest available quantitative information on GIS/AIS reliability, maintenance, land acquisition, site preparation costs and initial purchase costs. This analysis also accounted for "intangibles" such as safety, aesthetics and security that are often overlooked but becoming increasingly important.

Index Terms- power, ranking, reliability, substations

I. INTRODUCTION HIS paper presents a reliability analysis, economic evaluation and ranking on various substation configuration alternatives for the new 500 kV substation

near Ackerman, Mississipi. The substation will be constructed to interconnect two generators with combustion turbines at 350 MVA and 13.8 kV, and one generator with steam turbine at 230MVA and 13.8kV with a 700 MVA, 500 kV transmission line.

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The objective of this study is to:

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Find the substation design that achieves an optimal solution of reliability and cost. Establish a process to select a substation to optimize total life cycle cost rather than acquisition cost.

H. Rickel is an Engineering Director for Tractebel Power, Inc. in Houston, Texas

Dr. K. Koutlev is a principal consulting R&D engineer with ABB Inc., in Raleigh, North Carolina, phone: 919-856-3877; fax: 919-856-241 1; e-mail: krassinlir.koutlev@us.abb.com

R. Reymers is a Key Account Manager for ABB, Inc. in Raleigh, North Carolina

Dr. L. Tang is a head of ABB Corporate Research in US L. Willis is VP Assets Management Services for ABB, Inc. in Raleigh, North

Carolina

0 Predict the total project cost including initial construction cost, operation and maintenance cost, and cost of service unavailability. Evaluate substation alternatives using the life cycle cost and intangibles like environmental impact and substation performance.

To achieve the objectives we used two analytical software tools, SubRelTM and SubRankm developed in ABB Inc., USA. SubReP is used to model substation alternatives, assess reliability, and calculate life cycle costs. Then, the life cycle costs are combined with environmental and performance attributes for every substation alternative for overall estimation and comparison. This analytical task is performed using SubRankm software. Following the analyses performed with both tools the final decision about the substation configuration is made. The advantage of this approach is that the most suitable substation configuration is picked on the basis of reliability, life cycle costs, failure cost, and investment cost, along with intangibles such as safety, flexibility, ecological impact, security and aesthetics.

II. SUBSTATIONS RELIABILITY MODELS

SubRelTM software package was used to build the substation

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Assess substation reliability 0

reliability models. The software can: Create and modify substation alternatives Implement the substations models with AIS and GIs components

Calculate the investment cost, O&M cost, cost of poor reliability as well as the life cycle cost for every substation alternative.

SubRelTM uses dynamic state enumeration to compute the reliability of each alternative [ 1,2]. Essentially, SubRelTM models every possible contingency, determines the impact of each contingency to the reliability of each component, determines the frequency of each contingency, and sums up the impact of all contingencies for an overall reliability assessment.

The first thing that SubReP does is to determine the amount of time that a substation is in its normal operating state (NS). This is equal to the amount of time during one year minus the time spent in maintenance states (MS):

0-7803-81 10-6/03/$17.00 02003 IEEE 181

8760 - Time in MS loo % Time in NS= 8760

The program then simulates all faults that occur on components (while the system is in its normal operating state). For each faulted component, SubRel" follows the following sequence of events:

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The component experiences a fault. The nearest protection devices on all energized paths to the faulted component are tripped (the protection system is assumed to be perfect). After a delay (determined by the mean time to switch (MTTS) of sectionalizing points), the fault is isolated and the system is reconfigured to restore power to as many loads as possible. After the faulted component's mean time to repair (MTTR) is elapsed, the fault is repaired and the system reverts to its normal operating state.

Each of these faults will impact the reliability of various substation components in various ways. SubReP keeps track of the contribution of each fault to the outage frequency and outage duration of each component. These values are then weighted based on the failure rate of the faulted component and the probability of the system being in the normal operating state.

After simulating faults in the normal operating state, SubRel" simulates all maintenance states and all faults that occur during maintenance states. When a component is maintained, SubRel" automatically isolates the component using sectionalizing devices and reconfigures the system to restore power to as many loads as possible. This maintenance state will, of course, cause the component being maintained to experience an outage. It may also cause an outage on nearby components.

After SubRelTM determines the substation's maintenance state for a particular component, it will simulate faults during this state for all energized components. This fault simulation is identical to the method used during the normal state except that the system starts off in a different configuration.

Three feasible substation alternatives for the TractebeVChoctaw project were modeled using SubReP and the reliability model described above:

AIS Collector (Straight) Bus -Figure 1 AIS Ring Bus - Figure 2 GIs Ring Bus - Figure 3

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The reliability data used in the models are based upon long- term historic data available from published industry sources such as IEEE, CIGRE, the Canadian Electricity Association and others [3-71. The squares around the equipment in GIs Ring Bus configuration indicate the components located in one gas chamber. SubReP software is capable of simulating substation reliability calculations with integrated type modules [ 81.

8 Figure 1. AIS Collector Bus

Figure 2. AIS Ring Bus

I ... . .. . - . . .. .. . -.

Figure 3. GIS Ring Bus

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HI. REL,IABILITY RESULTS AND ANALYSIS

The reliability assessment for all alternatives was performed using the SubReP program. The assessment of the impact of substation configuration on reliability of the transmission line is the main purpose of this analysis. The calculated results include total outage frequency (OF) and total outage duration (OD) for the transmission line. There are two major reasons for the transmission line outages: equipment failure and equipment maintenance. Equipment failure outages are also called stochastic outages and they depend of the failure rate of the substation components. Equipment maintenance outages are also called determined outages, as they depend on the equipment maintenance schedule. The outages are split in this way following the assumption that outages of the transmission line due to planned maintenance will have a lower cost of interruption. The reliability results for the transmission line connection are shown in Table 1. Outages due to transmission line faults and maintenance are not included in the results below because they affect each configuration equally.

TABLE 1. TRANSMISSION LINE RELIABILm

The following major conclusions can be made regarding the reliability results in Table 1 :

GIs ring bus configuration has lower stochastic (due to equipment failure) outage frequency, once per 56.8 years versus once per 8.5 years for AIS ring bus and once per 4.7 years for AIS collector bus. GIs ring bus has also the lower determined (due to maintenance) outage frequency, once per 15 years compare with 1 per 2.5 years and 1 per 1.25 years. This is due to the low maintenance rate for GIs equipment. The total outage frequency for GIs ring bus is once per 11.9 years versus 1 per 1.9 years for AIS ring bus and more than once per year for AIS collector bus. GIs ring bus has lower stochastic outage duration compare with the other two alternatives although the differences are not so high like for the outage frequency. Regarding the determined outage duration GIs ring bus again has the best performance, i.e., 0.93 h/yr vs. 3.2 and 6.4 h/yr. The total outage duration for GIs alternative is 1.04 h/yr vs. 3.5 and 7.15 Wyr

The overall conclusion is that from reliability point of view, the GIs ring bus configuration has much better performance than the other two configurations. This difference is even

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stronger when we consider only the interruption frequency. After this assessment, the reliability of each segment of

each substation layouts can be color coded to reflect outage frequency, outage duration, etc. The color coded layouts provide an opportunity to analyze the entire substation and visualize the weaker spots in the layout. They allow an easy comparison between different substation designs or between the same designs with AIS and GIs configurations.

To determine the impact of all substation components on reliability of serving the transmission line, SubRelTM can also perform an impact area study. Additional pictures with shaded drawings for all alternatives by outage frequency impact, outage duration impact, and economic impact can be drawn.

IV. ECONOMIC EVALUATION

The following key variables and assumptions were considered for an economic evaluation of the proposed substation alternatives:

Investment cost

0 Reliabilityhnterruption cost The interruption costs are calculated on the basis of the cost

of interruption for the transmission line. Usually these costs are expressed as summary of the cost of interrupted energy [$/kWh] and cost of interrupted power [$/kWj. The first item is related with the outage duration and the second, with the outage frequency.

The present value of the life cycle costs is then determined from each of the variables mentioned above [9]:

Operation and maintenance cost (O&M cost)

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(1+p)" -1 L P * (1+ P)" 1 LCC = IC + [FC + vc] * where:

LCC = Life Cycle Cost IC = Investmentcost FC = O&M Cost, i.e., fixed annual cost VC = Interruption Cost, i.e., variable cost n = substation planned life time p = Interestrate

The investment costs for each of the investigated substation alternatives were developed by ABB and/or obtained as bounding values from Tractebel. The O&M costs included in the study are based on factory recommended maintenance programs obtained from AIS and GIs substation maintenance specialists.

The life cycle cost for the three substation alternatives was calculated assuming that the substation life will be 30 years. In order to fully analyze the impact on different interest rates and cost of interruption on the investigated substation alternatives, the following bounding data were provided by Tractebel's financial organization for the analysis.

Discount / interest Rates in [%] Cost of Energy Interruption in [$/kWh]

By way of illustration, Figure 4 shows the differences in the life cycle cost for three substation configurations A, B, and C.

Failure LCC mOBMLCC .

Inmstment Cost

Ufe Cycle Cost

15,000,MM

10,000,000

5,000,000

A B C

Figure 4. LCC for Different Substation Alternatives

In reality the LCC for every substation alternative varies with variations of the interest rate and cost of interruption. For example, Figure 5 shows the life cycle cost as function of the interest rate for two substation configurations, A and B.

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14,MO.OW 12,MO,WO 10,000.MI0

6 6,W0,000 4.000.000

: 8 . ~ . 0 0 0

A 2.w0.000 o J I I I I I 0.0 2.0 4.0 6.0 8.0 10.0

Interest rate[%]

Figure 5. LCC = f(Interest Rate)

By investigating all substation alternatives following the procedure from Fig. 4 and 5 we can find which substation configuration has lower LCC for the particular boundary conditions.

For TractebeYChoctaw project the investment cost was adjusted with bounding values for land acquisition and site preparation costs. The GIs ring bus footprint for this project was considerably smaller than for the AIS ring bus. The difference in the footprints significantly impacts the site preparation costs for TractebeVChoctaw project and favors the GIs configuration. It is clear also that the Life Cycle Cost cannot be the only consideration to make the final decision regarding the substation configuration.

V. RANKING SUFSTA~ON ALTERNATIVES Usually, when the final decision regarding the substation

configuration is to be made, the Life Cycle Cost and many additional objectives related to substation performance and its environmental impact should be considered. In reality, it is

very difficult to combine attributes that can be expressed in currency and subjective attributes like flexibility, safety and environmental impact. In order to solve this problem we developed a tool called SubRankTM. The tool is based on the multi-objective decision analysis using value hierarchy [ 101, and the idea for the application of multi-criteria analysis for substation design [ll]. The tool considers the following objectives and their attributes for substation ranking process:

Life Cycle Cost o Investment Cost o Site Preparation Cost o O&MCost o InterruptiodFailure cost

0 Substation Performance o Flexibility o Safety o Automation Level o Security

o Ecological Impact o Air Pollution Tolerance o AppearanceIAesthetics o Audible Noise Generated o EMF Generated o Radio/Television Interference Generated o Disposal Concerns

0 Environmental Factors

The values for the objectives and their attributes above are provided from Tractebel. The only requirement for the assigned weights is their sum to be equal to 1. In Figure 6 is presented a snapshot of the tool.

Figure 6. SubRank Input Screen

On the left hand side of the screenshot are entered all of the weights for the objectives and their attributes. On the right hand side are the attributes evaluation given for every substation alternative. As result, SubRankTM tool generates a graphical presentation of the ranking results shown in Figure 7.

The Tractebel analysis based on the SubRel results confirmed that the GIs option had the lowest life cycle cost. A separate analysis of the substation intangibles using

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Ranking of Alternative Substations DLF&Y&C&BP~EIIWJW~~I

I -0aa 0-800 0,800

0-600 0-500 ocl.00 0,300 0,200 0-100 O~OOU -

0,700

SubRankTM, reconfirmed that the GIs also had the best score among the selected options. The results of these analyses led Tractebel to the decision to procure the GIs ring bus substation configuration.

Figure 7. SubRank Ranking Screen

VI. CONCLUSIONS Tractebel’s conclusions following this assessment was that

the AIS vs. GIs choice was not as simple has had been previously believed. Only by using available analytical tools, by factoring in all project related and industry available information and by analyzing the results of the study, was a thorough assessment made and an optimal selection accomplished.

REFERENCES

R. E. Brown, T. M. Taylor, “Modeling the Impact of Substations on Distribution Reliability,” IEEE Transactions on Power Sysrems, Vol. 14, No. 1, Feb. 1999, pp. 349-354. K.G. Koutlev, R.E.Brown, “Substation Reliability Assessment and Analysis”, ABB Electric Utility Conference, March 1999. IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems, IEEE Std - 1997. Final Report of the Second International Enquiry on High Voltage Circuit Breakers Failures and Defects in Service, CIGRE, Working Group 06, Study Committee 13, June 1994 CIGRE WG 23.02, Report of the Second Intemational Survey on High Voltage GAS Insulated Substations (GIS) Service Experience, CIGRE Brochure, 2000 Forced Outage Performance of Transmission Equipment for period 1/1/1994 to 12/31/1998, Canadian Electricity Association, 2000 H. L. Willis, Power Distribution Planning Reference Book, Marcel Dekker, Inc., 1997. K. Koutlev, R. Brown, L. Tang, etc. System and Method for Reliability Assessment of a Power System Having Integrated Modules, SN 09/916,811, Patent Application Filed July 27,2001 Yarbrough, R.B., Electrical Engineering Reference Manual, 5th Rev. Ed., Professional Publications Inc.. Belmont. CA. 1997.

Howard Rickel received his Bachelor of Science Degree from the University of Nebraska in Lincoln, Nebraska and his Masters of Business Administration Degree from Houston Baptist University in Houston, Texas. He has extensive experience in power generation and transmission. He is currently an Engineering Director for Tractebel Power, Inc. in Houston, Texas. Krassimir G. Koutlev received his M.S. and Ph.D. in elecmcal engineering from the Technical University of Sofia (Bulgaria). He joined ABB-US in March 1998. Currently, he is a principal consulting R&D engineer at ABB Inc., Raleigh, NC and specializes in areas of reliability, power quality, DG, design optimization and system solution business. Prior to joint ABB he has 13 years experience in design, optimization, energy efficiency, reactive power compensation and power quality improvements in power distribution systems in Detroit, USA and Europe. He has been an IEEE member since 1997. Robert Reymers received his Bachelor of Science and Masters of Science Degrees in Electrical Engineering from Brown University in Providence, Rhode Island. He has extensive experience in power systems analysis and control and protection system design. He is currently a Key Account Manager for ABB, Inc. in Raleigh, North Carolina. He has been an IEEE member since 1967. Le Tang (M’95) joined ABB in August 1995. Le earned his B.S. in Electric Engineering from Wan Jiaotong University in 1982 and obtained his M.E. and Ph.D. in Electric Power System Engineering from Rensselaer Polytechnic Institute in 1985 and 1988 respectively. Le is currently managing ABB‘s Group R&D operation in the United States. He is involved in various types of research and development activities in power transmission and distribution areas. Prior to joining ABB, Le was a Senior Consulting Engineer at Electrotek Concept Inc., where he was responsible for a wide range of studies and seminars in power quality field. Lee Willis is VP Assets Management Services, ANN Inc., in Raleigh, North Carolina. He specializes in electric power distribution systems, electric utility planning and assets managefnent. With more than 25 years of experience helping utilities and governments worldwide improve their electric systems he is the author and coauthor of over 200 technical and scientific papers on electric power systems and four books. A Fellow of the IEEE, Mr. Williams received the B.S. (1971) and M.S. (1972) degrees in electrical engineering from Rice University, Houston, Texas.

, . [lo] D. Atanackovic, D. T. McGillis, F.D. Galiana, “The Application of Multi-

Criteria Analysis to Substation Design,” IEEE Transactions on Power Systems, Vol. 13, No. 3, August 1998, pp. 1172-1178.

[I I] C. W. Kirkwood, Strategic Decision Muking, Duxbury Press, Belmont, , CA, 1997.

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