Guidelines for Electric System Planning

Guidelines for Electric System

Planning (Transmission, Subtransmission, Distribution)

Near Term System Development Guidelines & Methodology

Standard Practices Document

Operations Section of Planning Guidelines Document

Authors: Origination Date: 1979 Version: 14 James Hunt Ken Alteneder Jose Silva Jeni Mistry Jeff Wruble Tom Olivas Barry Cummings Jason Gunawardena Hilen Cruz Thomas Keel Chris Francoeur Revised By: Jeni Mistry Revision Date: 05/09/2013 Approver’s Name: Brian Keel Approval Date: 05/16/2013

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INTRODUCTION

These Guidelines are intended to be a guide for the development of the Transmission, Subtransmission and Distribution Plans. These Plans are completed during the fourth quarter of each calendar year and become the basis for the Transmission, Subtransmission, and Distribution budget and future facility construction. It is intended that these Guidelines be reviewed as needed as a part of the overall plans process. The Planning Guidelines Committee, composed of representatives from Electric System Engineering, System Design & Construction, Transmission & Generation Operations, Electric System Operations & Maintenance, and System Planning & Performance is responsible for performing this review. Results of this review are summarized in this document.

It is intended that the guidelines not be used as a rigid rule for the development of future facility needs. It is recognized that alternative solutions may be developed for problems noted and evaluations and recommendations for these future facilities will be addressed as needed. It is possible that after considering all factors, including but not limited to economics, reliability and impact on system operations, exceptions could be made to the guidelines. It is also recognized that certain parameters may change as a result of in-depth engineering design evaluations and the general evolution of our system. Existing facilities can be modified to meet the guidelines, but should be done so on a cost effective basis.

The guidelines presented are for both planning study and operating study purposes. Separate sections of the document are devoted to each of these subjects. The Near Term Guidelines Section and the Standard Practices Section are directed toward the planning process and the Operations Section is devoted to studies of that nature. The Line & Equipment Ratings Section of the document is applicable to both planning and operating studies. The development of alternatives and exceptions to the guidelines will be reviewed during the normal planning process. At that time all affected parties will be made aware of any deviations.

A glossary of terms has been provided at the end of the Near Term Guidelines Section and the Standard Practices Section of the document. The definitions contained in the glossary are an important factor in understanding the meaning and intent of these guidelines.

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TABLE OF CONTENTS

INTRODUCTION...................................................................................................................................................................... 1

1. General .............................................................................................................................................................................. 3

2. Steady State Analysis (Planned System Limits for Transmission and Distribution) ............ 8

2.1. Normal Conditions (N0) ............................................................................................................................... 8

2.2. Single Contingency Outage Conditions (N1) ..................................................................................... 9

3. System Dynamic Response .................................................................................................................................. 12

4. Definitions ..................................................................................................................................................................... 14

5. APPENDICES ................................................................................................................................................................. 16

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1. GENERAL

The following paragraphs describe the near term system development guidelines, assumptions & study methodology used to plan SRP’s transmission, sub transmission and distribution systems. During all phases of the Bulk Electric System (BES) planning process (100 kV and above), Transmission & Generation Operations will be involved as appropriate in the process to ensure that the studies take into account the operational perspective.

1.1. Load 1.1.1. Forecast, Annual: The SRP’s system peak load forecast used for near term

planning is equal to the 10% risk forecast generated by the Forecasting Research & Economic Development (FRED) department. This forecast reflects a 1 in 10 probability of extreme weather and economic conditions and includes residential, industrial and mining area load. The residential component of the peak load forecast is allocated to the grid annually by System Planning & Performance using historical local area loads and a per unit saturation curve methodology that defines likely area growth trends and growth needs and the associated electric system expansion risk.

1.1.2. Forecast, Saturation: A peak load forecast designed to reflect the theoretical maximum or ultimate level possible in a given area. The recent development of a per unit saturation curve methodology has indicated that most areas will plateau at a load level of 11-12MW/square mile, and will approach saturation at about 15MW/square mile. The 2011 Saturation Forecast was developed by substation service area using 2006 load and land use information. The forecast includes load estimates by customer land use type, and since more accurate land use was available, a single saturated load estimate was developed for each substation service area.

1.2. Generation: Generation, sales and interchanges will be represented in planning studies in accordance with the latest SRP corporate Loads & Resources. Generating units in power flow cases will be committed and scheduled according to SRP’s planned scheduling practices after consultation with SRP’s Supply and Trading/Power Coordination group. Construction recommendations will generally be based on the economic commitment and scheduling of generating units. Generation patterns will be varied in system studies to evaluate the results of planned or forced generator outages, seasonal commitment, seasonal scheduling of units, and changes in fuel availability or prices, and/or economy interchanges. As a minimum test of the systems capability to accommodate different generation patterns, studies will investigate maximum and minimum generation levels for each normally scheduled valley plant (see TABLE A in Section 5.0). Import and load serving nomograms shall be referenced to determine correct Generation patterns. The following will be considered prior to recommendation of construction for other than economic generating unit commitment and scheduling.

Annual hours for which system capability could limit maximum generation at a plant to less than rated output.

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Cost of energy required above economic unit commitment and schedule to avoid system problems without construction of new facilities.

Cost of constructing or advancing construction of new facilities. PMax and Pmin for Power Flow Studies will be determined from Generation

Services, O&M Capacity, Generation for Transmission Planning.

1.3. Distributed Generation: Load forecast assumes distributed generation is off-line at peak load. Requests to interconnect to the distribution are evaluated as required in the SRP Distribution System Interconnection Procedure, a standards document. Future impact on the distribution system is evaluated on case basis.

1.4. Loop Flow: Power flow & stability studies are run with Western Electricity Coordinating Council (WECC) full loop cases. Where unscheduled flow (loop flow) is a concern a reasonable amount of WECC loop flow will be simulated. The scheduling practices of phase shifting transformers which are intended to control major and minor loop flow will be considered in system modeling decisions.

1.5. Lead Times: Based on Line siting requirements and EHV equipment procurement, the goal in planning is to keep the first three years of the 6-year plan fixed or unchanged if new lines are involved. Otherwise, the two year guideline is acceptable. The equipment lead time, public involvement, permitting, right of way constraints, design considerations etc. all contribute to the necessity of this as discussed below. Please note that a large load or expansion of existing load in remote areas may result in an addition in the fixed two year plan.

1.6. Lines: For New lines at all voltages above 12kV the primary constraint for construction is acquisition of a route and right-of-way. This includes conducting a PUBLIC PROCESS and, in the case of 115kV and above, receiving a CEC (Certificate of Environmental Compatibility) from the Arizona Corporation Commission. A brief description of the earliest year that a new line shall be introduced into the six year construction plan for the first time based on whether or not a public process and/or CEC permit will be required.

For a new 12kV line, no public process is required and the line can be introduced in the first year of plan.

For a new 69kV line, SRP does an internal public process and easement acquisition which could take two years. The line can be introduced in the third year of plan.

For new lines 100kV and above a CEC and Public process is required. If the proposed transmission line crosses land managed by any federal agency, including Bureau of Land Management (BLM), Forest Service, and Bureau of Indian Affairs (BIA), SRP is required to go through the federal National Environmental Policy Act (NEPA) process. These permits could take 2-3 years. So a new transmission line 100kV and above without any permits could be introduced to the plans in fourth year of the plan. If the permits for the new proposed line already exist than the line could be introduced in the second year of plan.

1.7. Substations, Residential: For new substations the primary lead time constraint for all voltage levels is the acquisition of the power transformer. Below is the brief description of the earliest year that a new substation can be introduced into the six

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year plan for the first time. Opportunities to shift planned equipment from one site to another and introduce in first year are an option provided technical requirements are met. Land acquisition is also a consideration and appropriate lead times are to be provided per System Planning & Performance and the Land Department.

69/12kV transformer: The transformer can be introduced to the second year of the plan provided a 69kV line exists nearby the substation. If a new 69kV line needs to be built which includes SRP internal public process, the transformer can be introduce in the third year of plan.

230/69kV transformer: The transformer can be introduced in the third year of the plan.

500/230kV transformer: The transformer can be introduced in the fourth year of the plan.

1.8. Substations, Industrial: A lead time of at least 14 months from the execution of a construction contract is desirable but in many cases may not be possible. Deadlines imposed by the customer may make it necessary to introduce for the first time new dedicated substations in the first year of the plan. It may be necessary to construct temporary facilities to meet the customer's deadlines. Lead times and/or availability of major equipment may ultimately dictate the schedule. Custom or non-SRP- Standard substation equipment could factor into the construction schedule.

1.9. Neighboring Utilities: Sufficient transmission capacity will be provided without relying on or unduly imposing upon any other utility's transmission system unless otherwise agreed to. Established loading limits for other utilities will be observed.

1.10. Three Terminal Lines: Three terminal lines shall be avoided wherever possible but may be implemented if system performance and cost compare favorably to other options. Nevertheless they will be allowed only if they do not compromise protection of the equipment involved as determined by the System Protection Group.

1.11. Line End Sectionalizing: Equipment (circuit breakers or load-break station disconnect switches) will be installed on each end of a 69kV line that is greater than three miles in length and on at least one end of all line sections providing looped line service to distribution substations. Exceptional line charging such as from a lengthy underground line will be evaluated where appropriate. Line dropping capabilities of disconnect switch accessories are given in the Substation Design Standards, section AK01.01. This standard specifies the Amps of charging current that can be interrupted by various devices such as SF6 bottles, vacuum bottles and whips. A calculation technique for approximate line charging current per mile of 69kV or 115kV line is also provided.

1.12. Power Circuit Breaker vs. Load Break Switch: When it has been determined that a 69kV load break switch is needed, an additional determination should be made concerning whether a power circuit breaker will be needed eventually in that same position. If a power circuit breaker will be needed eventually, the breaker, rather than the load break switch, should be installed initially, if funding is available.

1.13. Load Divider Breakers: Breakers will be installed for the purpose of complying with SRP’s 60MW criteria as follows. In cases where load between sectionalizing devices exceeds 60MW, a load divider breaker should be installed to limit loss of load

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for a single contingency. To determine the load divider breaker position, near term and long-term electric system plans (saturated load plan) shall be referenced. Industrial customers are not evaluated for the 60MW criteria.

1.14. Bus Divider Breakers: A load divider breaker that is added between substation bays to separate transformers when the total load at the station exceeds 60MW. Bus divider breakers are also installed to provide redundant feeds from the same substation to customers requiring enhanced/backup service.

1.15. 69/12kV Substation Locations: Normally 69/12kV substations are located approximately two miles apart. This results in a substation service area of approximately four square miles, which will have a saturated load for most substations of approximately 60MW. Future new sites in the Southeast Valley are planned to serve five square miles and 75MW. The sites are being purchased to accommodate 4-69kV bay positions, 3-69kV lines, and 1-69kV capacitor. This configuration will also allow three or four 69/12kV transformers depending on the need for a 69kV capacitor bank in the area. SRP has evaluated and recommended 21.6 kV distribution voltage for the Superstition Vista Area. For the 21.6kV voltage substations will serve about 10 square miles. No action is currently anticipated due to reduced load forecast. New substation sites are purchased based on a prioritized plan which includes a review of the current substation plan, and other factors.

1.16. 69/12kV Substation Site Size: To accommodate four possible bay positions the usable area within the substation should be 300 feet by 300 feet. Additional land may need to be purchased to account for municipal set back requirements.

1.17. New Substations: Consideration is given to opening up a new substation site when the load in its four square mile service territory exceeds 7MW.

1.18. 12kV Feeder Locations: Desired feeder locations are on the major mile streets, the 1/4 mile streets and the 3/4 mile streets in the north/south direction and on the mile and 1/2 mile streets in the east/west direction.

1.19. 12kV Feeder Getaways: Historically, 4-12kV feeders have been installed per each 69/12kV transformer addition. Now new switchgear orders come equipped with five feeder breakers allowing for the possibility of installing five 12kV feeders per transformer. In most residential areas, five feeder getaways will be installed per transformer. In light industrial and commercial areas, the need for four or five feeders will be evaluated on a case by case basis with consideration given to potential dedicated feeder service requests.

1.20. 12kV Feeder Interconnection: 12kV feeders are open looped, interconnected through normally open switches to allow seasonal balancing of loads on 69/12kV transformers and 12kV feeders. Switching is also performed to facilitate construction activities, isolate faulted line segments and restore load following an outage.

1.21. 12kV Fusing/SectionalizingOverhead: Overhead laterals typically have not been fused. However where reliability data indicates an unusually high incidence of outages of the entire circuit reclosers and sectionalizers are used on feeders and major laterals to limit the amount of interrupted load.

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1.22. 12kV Fusing/SectionalizingUnderground: The #2 primary underground cable is normally fused. The 4/0 and feeder cables are not fused. Underground sectionalizing is considered on a case-by-case basis when reliability data indicates an unusually high incidence of outages in a particular area that affects the entire circuit.

1.23. 12kV Reclosing: Typically, all non-dedicated 12kv circuits have reclosing installed. The reclosing practice gives three attempts to reclose before staying open due to a permanent fault unless high fault current locks out the recloser. Outside the substation reclosers are added in special cases where there are reliability concerns. Typically, dedicated circuits have reclosing removed.

1.24. Grid Modernization – “Smart Grid”: The guidelines in this document are based on historical practices to meet reliability targets. The existing T&D system is equipped with limited automation outside the receiving station and substation walls. Numerous “smart” technologies are on the horizon including Synchrophasor’s, transmission line monitors, real time substation equipment monitors and dynamic loading, distribution feeder automation, and remote fault indication. The goal with grid modernization is to optimize margins, increase equipment life and improve reliability.

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2. STEADY STATE ANALYSIS (PLANNED SYSTEM LIMITS FOR TRANSMISSION AND DISTRIBUTION)

The guidelines listed below are used in conducting a steady state analysis or a power flow study of the system.

2.1. NORMAL CONDITIONS (N0)

2.1.1. Loading Limits: Under normal conditions (pre-contingency) transmission and distribution facilities will not be loaded above the continuous rating.

2.1.1.1. Transformers: 525/230kV and 230/115kV transformers will not be loaded above 100% of the transformer “nominal/normal” rating specified in Transmission/Generation Transformer Loading Limits Document located in Substation Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

230/69kV transformers will not be loaded to above 100% of the transformer “nominal/normal” rating specified in Transmission/Generation Transformer Loading Limits Document located in Substation Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

69/12kV transformers will not be loaded above 85% of the emergency limit specified in Substation Transformers\Emergency Loading Data. This access database is located in the Substations Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

2.1.1.2. Overhead Lines: 500kV, 230kV, 115kV or 69kV lines and substation conductors will not be loaded above 100% of their summer normal limit based on the conditions and assumptions. The 12kV overhead lines and substation conductors will not be loaded above 70% of their emergency rating under steady state conditions. The overhead lines ratings can be found at: http://srp.gov/corpdocs/elecSyEng_standard/files/ratings)summary/ratingsSum.pdf

2.1.1.3. Underground Lines: 69kV & 12kV lines should not be loaded above 100% and 70% respectively of their maximum ampacity rating based on the conditions and assumptions. The underground lines ratings can be found at: http://srp.gov/corpdocs/elecSyEng_standard/files/ratings)summary/ratingsSum.pdf

2.1.2. Voltage Limits Equipment Based: Equipment high voltage limits will not be exceeded for normal conditions (n-0) or for the energizing or de-energizing of transmission lines. These normal Voltage Limits are found at: http://srp.gov/corpdocs/elecSyEng_standard/files/ratings)summary/ratingsSum.pdf

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2.1.3. Voltage Limits Customer Based: Customer service entrance voltage limits (high or low) will not be violated for normal conditions (n-0). These limits are described below the minimum established by ANSI. For 69kV and above system: The system voltage should be at 1.0 p.u or higher.

For 12kV: The voltage magnitude shall be maintained within the limits specified for customer service entrance voltage per ANSI (standard # C84.1-1989 or most current edition) as reflected on the 12kV bus. A voltage drop of up to 5% between the 12kV substation bus and the customer service entrance is considered acceptable for normal (n-0) conditions.

2.1.4. VAR Interchange: Under normal conditions the net VAR flow interchange with each individual neighboring utility shall be minimized and maintained near zero.

2.1.5. Power Factor: Var requirements shall be evaluated at each substation. Substation and 12kV line capacitors will be added to produce unity power factor on the 69kV side of the residential transformer. Capacitor additions for industrial substations will be evaluated separately on a case-by-case basis.

2.1.6. 12kV Zone Load Limits: 12kV line switches with load break capability will be added to the feeder system to aid in the transferring of load between sources. Load break switches are also recommended to split up zones with greater than 3,000 kVA connected load, which relates to the typical margin in 12kV feeders and 69/12kV substation transformers.

2.2. SINGLE CONTINGENCY OUTAGE CONDITIONS (N1)

2.2.1. Loading Limits: Single Contingency outage conditions will not result in overloaded electric facilities. Specifically, a single contingency outage will not cause transformer or line overloads as described below:

2.2.1.1. Transformers: 525/230kV, 230/69kV, 230/115kV and 69/12kV transformers will not be loaded above 100% of the emergency limit specified in the Substations Equipment database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

2.2.1.2. Overhead Lines: 500kV, 230kV, 115kV, 69kV, and 12kV lines and substation conductors will not be loaded above 100% of their emergency limit. The ratings for the 12kV and above conductor is included in Line and Equipment Ratings Document. http://srp.gov/corpdocs/elecSyEng_standard/files/ratings)summary/ratingsSum.pdf

2.2.1.3. Underground Lines: 69kV & 12kV underground conductors will not be loaded above 100% and 70% respectively of their emergency limit. Existing 69kV and 12kV Underground Cable ratings are included in the Line and Equipment Ratings Document. http://srp.gov/corpdocs/elecSyEng_standard/files/ratings)summary/ratingsSum.pdf

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2.2.2. Voltage Limits – Equipment Based: Customer service entrance voltages will be maintained within the high/low established limits for single contingency outages. These limits are described below:

For 115kV and above: the voltage deviation at any bus shall not exceed 5% of the pre-outage voltage.

For 69kV: The subvolt calculated values (See Section 5, Table B) should be used for N-1 voltage limits. This considers worst-case load level and power factor (site specific for industrial substation customers) or Load Tap Changer settings (for distribution substations). For 12kV: The voltage magnitude shall be maintained within the limits specified for customer service entrance voltage per ANSI (standard # C84.1-1989 or most current edition) as reflected on the 12kV bus. A voltage drop of up to 8% between the 12kV substation bus and the customer service entrance is considered acceptable for emergency (N-1) conditions. A voltage rise of up to 6% for the same conditions is also considered acceptable.

2.2.3. +20MW Criteria: The ability of the 69kV system and 230/69kV transformers to accommodate distribution system changes under single contingency outage conditions will be tested by studying the system with 20MW of load above the forecast moved from substation to substation (residential ). This test is intended to permit rapid response to industrial plant siting or expansion, and to address changes in small area load forecasts and the transfer of load between distribution substations for distribution system disturbances or for seasonal switching. Construction projects resulting from application of this guideline will be considered and recommended on a risk evaluation and cost/benefit basis.

2.2.4. Loss of Load: Single Contingency outages at 230kV or higher system voltages (including 230/69kV transformers) will not result in loss of load.

Single contingency outages on the 69kV system will not result in the loss of more than 60MW of SRP load. In tabulating the load lost for a single contingency outage only SRP residential load will be considered. APS and other utilities load such as Gilbert, Chandler & Papago Buttes APS load will be excluded from the 60MW calculation. For radial loads, fringe areas and at the edge of islanded receiving station areas where there is limited support from adjacent substations, the maximum load allowed to be lost during a 69kV single contingency outage will be separately evaluated. Other factors to be considered in evaluating loss of load risk include type of line construction (steel or wood), line age, outage history, and requirements of our customers

Single contingency outages of 69/12kV transformers and/or 12kV lines will result in loss of customer load because the distribution system is an open-looped radial system. Existing 12kV feeder radials and laterals having greater than 3,000 kVA connected should be looped with adjoining feeders using a N.O. switch to allow for quicker restoration of customer loads.

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12kV feeder routing should be planned to assure feeders from the same bay do not serve the same area. This only applies when multiple bays serve a specific area.

When multiple bays exist within a substation, two feeders from the same bay should not be constructed on the same overhead pole.

2.2.5. Mobile/Modular Transformers: Several mobile and modular unit substation (MUS) transformers are available for construction, maintenance and emergency conditions such as transformer failures. Most distribution growth areas are constructed with sufficient 12kV ties to restore customer loads without the use of a mobile transformer. In some areas, mobile transformers will be installed following a transformer outage to allow area loading to return closer to normal levels. When commercial customers do not have dedicated redundant transformers and when load exceeds capacity of existing mobiles, consideration should be given to purchasing a larger mobile transformer and/or having the customer purchase redundant capacity. For mobile and MUS availability call DOC.

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3. SYSTEM DYNAMIC RESPONSE

The guidelines listed below are used in conducting transient and inter-area oscillatory stability studies. 3.1. Flow Margin: 7% generation margin will be factored into stability limits to

compensate for uncertainty in modeling

3.2. Fault Damping: Generator fault damping, which represents machine internal losses, will be applied for close-in 3-phase faults. Generator fault damping is not represented for simulation of single-line-to-ground faults. Fault damping, when applied, amounts to the following percentage of max generator output as defined below. Navajo Units 1‐3= 6% Palo Verde Units 1‐3= 7.2485% Four Corners Units 4‐5= 10% Coronado Unit 1‐2=12.5% Cholla Unit 2‐4= 10%

3.3. Gap Flashing: Series capacitors whose gaps will flash as a result of a fault will be removed from the system at fault inception. Series capacitors with high speed reinsertion will be reinserted when the fault is cleared. The list of series capacitor in Arizona is listed in section 5 Table C. Not all series capacitor will flash. Contact the system operator to verify the operation of the series capacitor.

3.4. Unit Tripping: The system will not be dependent on unit tripping to maintain stability for single contingency outages. Unit tripping or load shedding may be considered for multiple contingency outages to maintain system stability.

3.5. Unsuccessful Automatic Reclosing: For single contingency outages, system

stability will be maintained for unsuccessful re-closing of transmission lines with automatic re-closing. Check with PDO where auto reclosing is available.

3.6. Disturbances: Three phase faults will be simulated and will be cleared within an

established total clearing time, which includes relay operating time, breaker opening time and one cycle for margin. Single-line-to-ground faults will be simulated assuming the failure of one breaker to clear (i.e. Stuck Breaker) near the fault. Total clearing time will include time for the backup breakers to clear. See System Protection for clearing time of each outage.

3.7. System Stability: All machines in the system are to remain in synchronism with the system as demonstrated by their relative rotor angles.

3.8. System Damping: System damping will exist as demonstrated by the damping of relative rotor angle swings and the damping of voltage magnitude swings.

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3.9. Transient Voltage: Voltage swings initiated by a simulated system disturbance shall not cause the voltage at system busses to exceed those limits specified in the WECC TPL-001-WECC-RBP-2 System Performance Regional Business Practice. http://www.wecc.biz/library/Documentation%20Categorization%20Files/Regional%20Business%20Practices/TPL-001-WECC-RBP-2.pdf

3.10. Post Transient Voltage: After fault clearing, steady state system voltages shall

remain within those limits specified in the WECC TPL-001-WECC-RBP-2 System Performance Regional Business Practice. http://www.wecc.biz/library/Documentation%20Categorization%20Files/Regional%20Business%20Practices/TPL-001-WECC-RBP-2.pdf

3.11. Transient Frequency: Frequency swings initiated by a simulated system disturbance shall not cause the frequency at system busses to exceed those limits specified in the WECC TPL-001-WECC-RBP-2 System Performance Regional Business Practice. http://www.wecc.biz/library/Documentation%20Categorization%20Files/Regional%20Business%20Practices/TPL-001-WECC-RBP-2.pdf

http://www.wecc.biz/library/Documentation%20Categorization%20Files/Forms/AllItems.aspx?RootFolder=%2Flibrary%2FDocumentation%20Categorization%20Files%2FRegional%20Business%20Practices&FolderCTID=0x01200015E7900DB2E794468FDE06D520B95C07&View=AD6002B2-0E39-48DD-B4B5-9AFC9F8A8DB3



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4. DEFINITIONS

CAIDI: Customer Average Interruption Duration Index. This reliability index is the average duration per interruption. When a customer is interrupted, CAIDI is the average time it takes to restore service to that customer. It is expressed mathematically as:

= Annual Total Customer-Minutes Out of Service Total Annual Number of Customer-Interruptions

Element, Single: A transmission, subtransmission and distribution line, bus or transformer which can be isolated from the system by the operation of an existing sectionalizing device or devices (either manual or automatic). Forecast, Annual: The SRP’s system peak load forecast used for near term planning is equal to the 10% risk forecast generated by the Forecasting Research & Economic Development (FRED) department. This forecast reflects a 1 in 10 probability of extreme weather and economic conditions and includes residential, industrial and mining area load. The residential component of the peak load forecast is allocated to the grid annually by System Planning & Performance using historical local area loads and a per unit saturation curve methodology that defines likely area growth trends and growth needs and the associated electric system expansion risk. The sum of the area total load will match the corporate high risk forecast for T&D. Forecast, Saturation: A peak load forecast designed to reflect the theoretical maximum or ultimate level possible in a given area. The recent development of a per unit saturation curve methodology has indicated that most areas will plateau at a load level of 11-12MW/square mile, and will approach saturation at about 15MW/square mile. Normal Conditions: Normal conditions (n-0) exist when all distribution, subtransmission, transmission and generation elements composing the normal system configuration are in service. Under these conditions there are no forced or planned outages. Outage, Breaker to Breaker: An outage of a single element or combination of elements brought about by the operation of automatic sectionalizing devices as invoked by the primary protection scheme. A 69kV bus outage at a receiving station would be an example of a Breaker to Breaker Outage. Outage, Single Element: An outage of a single transmission, subtransmission or distribution element. Outage, Single Contingency: A single contingency outage (n-1) can be either one of the following two types of outages: 1) Breaker to Breaker Outage which is an outage of a single element or combination of elements brought about by the operation of automatic sectionalizing devices OR 2) Single Element Outage which is an outage of a single transmission or subtransmission element. 60 MW Criteria: The 60MW criteria is applied to the 69kV transmission system only. Single contingency outages on the 69kV system should not result in the loss of more than 60MW of

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SRP load. On the distribution system, 60MW represent, on average, the load of three substation transformers. If a single contingency outage takes out this amount of load in a given area it would be impossible to restore all service via 12kV switching. SAIDI: System Average Interruption Duration Index. SAIDI is a reliability duration index. It is the number of minutes during a year that the average customer is without power and is applied to all customers. It is expressed mathematically as:

= Annual Customer-Minutes Out of Service Number of Customers Served

SAIFI: System Average Interruption Frequency Index. SAIFI is a reliability frequency index. It is the number of times the average customer experiences a sustained interruption in a year and is applied to all customers. It is expressed mathematically as:

= Annual Number of Sustained Customer Interruptions Number of Customers Served

Three Terminal Line: A sub transmission or transmission line connecting three stations with a source behind each, requiring circuit breakers at each station to operate to clear faults. MAIFI: Momentary average Interruption Frequency Index: MAIFI is a reliability frequency index. It is the number of times the average customer experiences a momentary interruption in a year and is applied to all customers. It is the SAIFI for interruptions of one minute or less. It is expressed mathematically as:

= Annual Number of Momentary Customer Interruptions Number of Customers Served

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5. APPENDICES

GENERATOR

MINIMUM

OUTPUT (MW)

KYRENE 1-2 N/A

KYRENE 4-6 4 each

KYRENE 7 150 (0-150 AGC no fly zone)

AGUA FRIA 1-2 40 each

AGUA FRIA 3 60

AGUA FRIA 4-6 5 each

SANTAN 1-3 (230kV) 20 each

SANTAN 2-4 (69kV) 20 each

SANTAN 5A 95-100*

SANTAN 5B 95-100*

SANTAN 5S 52-128**

SANTAN 6A 95-100*

SANTAN 6S 62

* Santan 5A,5B and 6A must achieve mode 6 for emmissions compliance

** Santan 5S 1:1 minimum 52, 2:1 minimum 128

TABLE A

MINIMUM VALLEY GENERATION LEVEL FOR PLANNING PURPOSE

Substation Name Voltage Level (kV) Substation Voltage Limit (p.u)

24.7E12N 69 0.923

AHWA 1 69 0.929

AHWA 2 69 0.899

AIRPARK 69 0.910

ALAMEDA1 69 0.923

ALAMEDA2 69 0.899

ALAMEDA3 69 0.899

ALAMEDA4 69 0.923

ALHAMBR1 69 0.899

ALHAMBR2 69 0.899

ALHAMBR3 69 0.899

ALTAVIS2 69 0.923

ALTAVIS3 69 0.923

AMERICA 69 0.923

AMOS 69 0.923

ANDERSON 69 0.929

APACHE 69 0.923

ARCADIA2 69 0.917

ARCADIA3 69 0.917

ARIZONA2 69 0.923

ARIZONA3 69 0.923

AUSTIN 69 0.936

BARCELON 69 0.917

BARTLETT 69 0.923

BASELIN3 69 0.923

BASELIN4 69 0.929

BASSHAM 69 0.923

BEELINE1 69 0.923

BEELINE2 69 0.923

BEELINE3 69 0.923

BIGSPINN 69 0.923

BINARY 69 0.910

BOGLE 69 0.929

BOONE 69 0.929

BROADWA2 69 0.923

BROADWA4 69 0.923

BROOKS 69 0.923

BUCKHOR1 69 0.923

BUCKHOR2 69 0.923

BURTON 69 0.929

CAMERON1 69 0.923

CARREL 115 0.956

CARTWRI2 69 0.929

SUBSTATION SUBVOLTS LIMITS

TABLE B


CARTWRI3 69 0.929

CARTWRI4 69 0.929

CASEY 69 0.929

CASHION2 69 0.905

CASHION3 69 0.923

CASHION4 69 0.923

CASHION5 69 0.929

CEDRSTR1 69 0.910

CEDRSTR2 69 0.917

CENTENNI 69 0.910

CHAMBERS 69 0.888

CHAPARRA 69 0.929

CHEATHAM 69 0.929

CHOPPER 69 0.872

CHRISTY 69 0.899

CITRUS 0 69 0.929

CITRUS 2 69 0.893

CITRUS 3 69 0.893

CLARK 69 0.929

CLEMANS3 69 0.923

CLUFF 69 0.929

COLLIER 69 0.899

CONOVALO 69 0.923

COOK 2 69 0.899

COOLEY 69 0.916

COOPER 69 0.929

CORBELL 69 0.923

CORTEZ 1 69 0.895

CORTEZ 2 69 0.895

COWDEN 69 0.929

CROSSCUT 69 0.942

CULBERTS 69 0.905

DELTA 2 69 0.895

DISPLAY 69 0.906

DOBSON 1 69 0.923

DOBSON 2 69 0.923

DOBSON 3 69 0.923

DORMAN 69 0.923

EALY 2 69 0.929

EALY 4 69 0.929

EGAN 69 0.929

EVANS 69 0.929

EVERGREE 69 0.923

FAIRWAY 69 0.923

FALCON 1 69 0.895

FALCON 3 69 0.936


FALLS 69 0.923

FERRIS 69 0.910

FINLEY 69 0.923

FLORENCE 69 0.923

FLUME 69 0.895

FOOTHILL 69 0.923

FOUNDRY 69 0.913

FOUNTAIN 69 0.923

FRAZIER 115 0.926

FREESTON 69 0.923

GAUCHO 2 69 0.923

GAUCHO 3 69 0.923

GAUCHO 4 69 0.923

GERMANN 69 0.902

GILA 2 69 0.913

GILA 3 69 0.923

GILA 4 69 0.923

GLENBROO 69 0.929

GLENN 69 0.923

GRASMOE2 69 0.923

GRASMOE3 69 0.923

GREENFLD 69 0.929

GREER 69 0.923

GRISWOLD 69 0.929

HANGER 1 69 0.923

HANGER 2 69 0.923

HANGER 3 69 0.923

HANSON 69 0.923

HARMON 69 0.929

HEARD 1 69 0.943

HEARD 2 69 0.899

HEARD 3 69 0.899

HIGHLINE 69 0.923

HOKAM 2 69 0.923

HOKAM 3 69 0.929

HOKAM 4 69 0.925

HOKAM 5 69 0.899

HOOPES 69 0.895

HOUSTON 69 0.923

HUGHES 69 0.923

HUMPHREY 69 0.923

HUNT 69 0.929

HURLEY 1 69 0.923

HURLEY 4 69 0.923

INDIANB1 69 0.929

INDIANB2 69 0.923


INDIANB3 69 0.912

INGLESI2 69 0.894

INGLESI3 69 0.899

IRVIN 69 0.929

ISAAC 69 0.923

JEPSEN 69 0.923

JONES 69 0.929

KAY 69 0.929

KEMPTON1 69 0.923

KEMPTON2 69 0.947

KEMPTON3 69 0.947

KIRK 69 0.923

LACY 69 0.923

LASSEN 1 69 0.917

LASSEN 2 69 0.923

LASSEN 3 69 0.923

LEHI 2 69 0.899

LEHI 3 69 0.923

LEISURE1 69 0.917

LEISURE2 69 0.899

LINOX 69 0.895

LUNA 69 0.895

MADISON 69 0.923

MANOR 69 0.929

MARCOS 2 69 0.899

MARCOS 3 69 0.899

MARCOS 4 69 0.923

MARLETT2 69 0.923

MARLETT3 69 0.923

MARLEY 69 0.923

MARYVAL3 69 0.923

MARYVAL4 69 0.923

MCCOY 69 0.923

MCPHERSO 69 0.923

MCREYNO2 69 0.923

MEACHAM 69 0.923

MEMORY 69 0.922

MICCHIP 69 0.922

MICRO 1 69 0.899

MICRO 2 69 0.883

MICRO 3 69 0.883

MILLER 1 69 0.929

MILLER 2 69 0.931

MILLER 3 69 0.931

MONUMENT 69 0.893

MOODY 1 69 0.929


MOODY 2 69 0.929

MOORE 69 0.923

MORCOM 69 0.923

NEELY 69 0.929

NOACK 69 0.923

NOBLE 69 0.903

NORTHER1 69 0.929

NORTHER3 69 0.923

NORTHER4 69 0.923

OLIVE 69 0.929

OMEGA 69 0.906

OSBORN 2 69 0.899

OSBORN 3 69 0.893

OWENS 2 69 0.929

OWENS 3 69 0.929

OWENS 4 69 0.923

PACE 69 0.923

PARKER 69 0.917

PENDERGS 69 0.923

PERA 69 0.911

PICKREL2 69 0.905

PICKREL3 69 0.910

PICO 69 0.894

PIMASRP2 69 0.923

PIMASRP3 69 0.899

PINKERTO 69 0.929

POTTER 69 0.929

PRINGLE 69 0.923

QUAIL 1 69 0.929

QUAIL 2 69 0.923

QUAIL 3 69 0.923

QUEENCRE 69 0.929

REED 2 69 0.917

REED 3 69 0.909

RICE 1 69 0.923

RICE 2 69 0.923

RICE 3 69 0.923

RIOVERDE 69 0.941

RITTENHO 69 0.936

RIVERSI4 69 0.899

ROE 1 69 0.923

ROE 2 69 0.923

ROE 3 69 0.923

ROHRIG 69 0.929

ROTH 69 0.929

ROVEY 69 0.923


RUPPERS 69 0.929

SAGE 2 69 0.923

SAGE 3 69 0.923

SAGE 4 69 0.923

SANCARL2 69 0.923

SANCARL3 69 0.923

SANDERSO 69 0.929

SAYLOR 1 69 0.923

SAYLOR 2 69 0.929

SAYLOR 3 69 0.924

SCOTTSDA 69 0.923

SCUSSEL 69 0.923

SEARGANT 69 0.923

SEATON 1 69 0.923

SGNLBUT3 69 0.905

SGNLBUT4 69 0.905

SHANNON 69 0.923

SHAW 69 0.923

SHEELY 69 0.929

SHIPLEY 69 0.923

SHULTZ 1 69 0.923

SHULTZ 2 69 0.923

SINNOTT 69 0.923

SOUTHERN 69 0.937

SPARTAN 69 0.923

SPEEDWAY 69 0.910

SPURLOCK 115 0.956

SQUAWPEA 69 0.931

STADIUM 69 0.923

STAPLEY1 69 0.923

STAPLEY2 69 0.923

STAPLEY3 69 0.899

STELLAR 69 0.903

STOKER 69 0.923

SUNLAKES 69 0.923

SUNSET 2 69 0.923

SUNSET 3 69 0.923

SUNSET 4 69 0.923

SUPERST2 69 0.911

SUPERST3 69 0.929

SYNERGY 69 0.886

TAVAN 69 0.917

TEMPESRP 69 0.923

TENNEY 69 0.929

TOLBY 69 0.923

TOVREA 69 0.923


TRASK 115 0.550

TRESRIOS 69 0.911

TRYON 69 0.923

TURPEN 69 0.929

TWEEDY 69 0.923

UNIFIED 69 0.917

UNIVERSI 69 0.923

VALENCI2 69 0.923

VALENCI3 69 0.929

VALENCI4 69 0.923

VALVIST1 69 0.903

VALVIST2 69 0.903

VALVIST3 69 0.903

VENTURE 69 0.923

VERDESRP 69 0.910

W.CONTN 69 0.929

WAFER 69 0.910

WALKER 69 0.923

WARD 69 0.923

WASSER 69 0.923

WATKINS 69 0.923

WEBBER 69 0.929

WEILER 69 0.923

WELBORN2 69 0.899

WELBORN3 69 0.923

WER MUS 69 0.929

WESTWOO1 69 0.899

WESTWOO3 69 0.899

WESTWOO4 69 0.899

WHEELER 69 0.929

WILKINS1 69 0.929

WILKINS2 69 0.899

WILKINS3 69 0.923

WILLIAMS 69 0.927

WILLIS 69 0.923

WINSOR 69 0.929

WOOD 1 69 0.923

WOOD 2 69 0.923

WORTMAN 69 0.929

ZIMMERMN 69 0.923

TABLE C

LIST OF SERIES CAPACITORS IN ARIZONA 2013 VOP CASE

500kV lines

Cholla – Saguaro (Cholla end)

Coronado – Silver King (both ends)

Four Corners – Moenkopi (Moenkopi end)

Mead – Perkins (both ends)

Moenkopi – Cedar Mountain (Moenkopi end)

Moenkopi – El Dorado (both ends)

Navajo – Crystal (both ends)

Navajo – Dugas (both ends)

Navajo – Moenkopi (Moenkopi end)

Yavapai – Westwing (Westwing end)

345kV lines

Flagstaff – Glen Canyon 2 lines (Flagstaff ends)

Flagstaff – Pinnacle Peak WAPA 2 lines (Pinnacle Peak ends)

Four Corners – West Mesa (West Mesa end)

Four Corners – Cholla 2 lines (Cholla ends)

Liberty – Peacock (Liberty end)

Peacock – Mead (Mead end)

San Juan – McKinley 2 lines (McKinley ends)

Springerville – Greenlee (Greenlee end)

Springerville – Vail2 (both ends, although the Springerville end may be physically at Greenlee for

distance)

Winchester – Vail (Vail end)

230kV lines

Kayenta – Shiprock (Kayenta end)

Kayenta – Longhouse Valley (Kayenta end, may be bypassed or not actually existing)

Other series compensated lines that may impact studies in Arizona

San Juan – B-A 345kV (B-A end)

Macho Springs – Luna (probably Luna end)

Hoodoo Wash – North Gila (North Gila end)

North Gila – Imperial Valley (Imperial Valley end)

Imperial Valley – Miguel (Imperial Valley end)

Ocotillo – Suncrest 500kV (probably Suncrest end if the compensation is in service, new “Sunrise”

Imperial Valley – San Diego project)

Palo Verde – Devers (both “ends”, actual compensation is roughly ¼ the line length in from each end,

will change with new Colorado River station)

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1.0 SUBSTATIONCONFIGURATION..........................................……………. 30 1.1 500kV Stations......................................................................................... 30 1.2 230kV Receiving Stations ....................................................................... 30 1.3 115kV Receiving Stations ....................................................................... 32 1.4 69kV Facilities at a 230/69kV Receiving Station..................................... 32 1.5 69kV & 115kV Facilities at Distribution Stations ...................................… 33 1.6 12kV facilities at a 69/12kV Distribution Station....................................... 35 2.0 TRANSFORMERS.......................................................……………………. 35 2.1 500/230kV Transformers ........................................................................ 35 2.2 230/115kV Transformers ........................................................................ 36 2.3 230/69kV Transformers .......................................................................... 36 2.4 69/12kV Transformers ............................................................................ 36 3.0 CIRCUIT BREAKERS, CIRCUIT SWITCHES & TRANSFORMER PROTECTORS.............................................................................................. 37 3.1 500kV Circuit Breakers ........................................................................... 37 3.2 230kV Circuit Breakers ........................................................................... 37 3.3 115kV Circuit Breakers ........................................................................... 37 3.4 69kV Circuit Breakers at Receiving Stations........................................... 37 3.5 69kV Circuit Breakers at Distribution Stations ........................................ 37 3.6. 69kV Transformer Protectors.................................................................. 37 3.7 12kV Circuit Breakers ............................................................................. 37 3.8 12kV Circuit Switches ............................................................................. 37 4.0 COMPENSATION, SHUNT & SERIES..................................................... 38 5.0 TRANSMISSION LINES & 12kV FEEDERS............................................ 39 5.1 500kV Transmission Lines...................................................................... 39 5.2 230kV Transmission Lines...................................................................... 39 5.3 115kV Transmission Lines...................................................................... 39 5.4 69kV Transmission Lines........................................................................ 39 5.5 12kV Feeders ......................................................................................... 40 6.0 DEFINITIONS........................................................................................... 41 7.0 FIGURES & TABLES .............................................................................. 42

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1.0 SUBSTATION CONFIGURATION:

1.1 500kV Stations

1.1.1 Bus Configuration: Substations with up to 4 terminations will be constructed in a ring bus configuration as a minimum. The actual final configuration will be the result of negotiation/compromise between participants in the substation. Beyond the fourth termination, the cost versus benefit for the station conversion to a Breaker and a half configuration will be evaluated on a case by case basis. Conversion to a full Breaker and a half arrangement will not occur later than the seventh termination to the station.

1.1.2 Bus/Bay Ampacity: Main buswork in transmission stations using rigid

bus shall be rated for 5400 Amps, normal summer rating. Bus conductor for 5400 Amp buswork shall be 6” schedule 80 round Aluminum bus tubing made of 6063-T6 alloy.

Cross-bay bus shall be designed for 3000 Amp capacity, normal summer loading.

1.1.3 Arrester Rating: Metal oxide surge arresters for line & station

equipment will have a maximum continuous voltage rating at least equal to the maximum continuous line to neutral operating voltage.

1.1.4 Equipment Voltage Rating: Station equipment will have a maximum

voltage rating of 550kV. Line equipment will have a maximum voltage rating of 550kV. See link for Line/Equipment Rating Section: \\srp.gov\corpdocs\ElecSyEngStandards\Files\Ratings Summary\RatingsSum.pdf (Table 9).

1.2 230kV Receiving Stations

1.2.1 Looped Service: New 230kV stations will be provided loop line service

(preferred) or have planned loop service within the planning horizon. Non looped stations will be allowed for the loss of the single 230kV line without impacting customers. Non looped stations will be allowed if there are no maintenance issues. Stations will include circuit breakers.

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1.2.2 Bus Configuration: Initial development of 230kV substations will, as a

minimum, be a Ring Bus configuration through the sixth termination. Load growth potential and inter-utility or industrial customer interconnection requirements may justify a ring or breaker-and-a-half initial bus configuration. Beyond the sixth termination, the cost versus benefit for the station conversion from Ring Bus Configuration to a Breaker and a half configuration will be evaluated on a case by case basis.

1.2.3 Max # Transformers: A maximum of four 100/133/167-187 MVA or four

150/200/250-280 MVA 45 C-55 C transformers will be installed for a substation capacity of 560 MVA or 840MVA to allow for an outage of one transformer without dropping load. The maximum number of transformers in a substation is limited by the short circuit duty at the substation and the need for islanding.

1.2.4 Line Terminations: The 230kV bus configuration will allow for

termination of a minimum of four 230kV lines unless generators or transmission system interconnections with others are involved.

1.2.5 Transformer Addition vs New Station: Consideration will be given to

the relative merits of opening a new 230/69kV station versus adding a transformer to an existing 230/69kV station. Factors to be taken into consideration include initial cost, long term cost, availability of a site, short circuit duty, power quality, reliability, plateau load level etc.


bus shall be rated for 5400 Amps, normal summer rating. Bus conductor for 5400 Amp buswork shall be 6” schedule 80 round Aluminum bus tubing made of 6063-T6 alloy. Cross-bay bus shall be designed for 3000 Amp capacity, normal summer loading.

1.2.7 Arrestor Rating: Metal oxide surge arresters will have a maximum

continuous voltage rating at least equal to the maximum continuous line to neutral voltage.

1.2.8 Short Circuit Duty: Short circuit withstand for rigid bus in transmission

stations shall be 50 kA minimum. Additional short circuit withstand may be required based on results of planning studies. Short circuit withstand shall be calculated using the procedure in SRP Design Procedure BM05.01 located in Substation Design Standards at: http://insidesrp/elsyseng/electricsys/substd.html

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1.3 115kV Receiving Stations

1.3.1 Bus Configuration: The bus configuration will be a ring bus through the fourth termination. Beyond the fourth termination a cost/benefit analysis will be conducted to determine if the configuration should be converted to a breaker and a half scheme.

1.3.2 Bus/Bay Ampacity: 115kV bus and cross-bays shall be designed for

1200 or 2000 amperes continuous duty on a case-by-case basis.

1.3.3 Arrestor Rating: Metal oxide surge arresters for the station will have a maximum continuous voltage rating at least equal to the maximum continuous line to neutral voltage.


stations shall be 40 kA minimum. Additional short circuit withstand may be required based on results of planning studies. Short circuit withstand shall be calculated using the procedure in BM05.01 in substation Design Standards at: http://insidesrp/elsyseng/electricsys/substd.html

1.4 69kV Facilities at a 230/69kV Receiving Station

1.4.1 Line Terminations: A maximum of eight 69kV lines will be terminated.

Unless interconnections with generators or with others are involved.

1.4.2 Bus Configuration: The fully developed 69kV bus configuration will be a zig-zag bus scheme with double breakers for at least two of the four 280 MVA transformers. The remaining terminations will generally be through single breakers on opposite busess in a zig-zag bus arrangement. Elements will be double breakered to meet single contingency outage criteria with special consideration given for sensitive customers.


bus shall be rated for 5400 Amps, normal summer rating. Bus conductor for 5400 Amp buswork shall be 6” schedule 80 round Aluminum bus tubing made of 6063-T6 alloy. Cross-bay bus shall be designed for 3000 Amp capacity, normal summer loading.


stations shall be 44 kA minimum. Additional short circuit withstand may be required based on results of planning studies. Short circuit withstand shall be calculated using the procedure in SRP Design Procedure BM05.01 located in: http://insidesrp/elsyseng/electricsys/substd.html

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1.5 69kV & 115kV Facilities at Distribution Stations

1.5.1 Line Terminations, Location: 69kV lines should be terminated at 69/12kV facilities in the outermost developed bay positions. This is to eliminate removing more than one bay from service for maintenance or construction activity. How and whether this will be physically accomplished will be determined on a case by case basis.

1.5.2 Line Terminations, Max Number: For reliability and single contingency

considerations more than 2 line terminations may be required at a substation. When the number of line terminations exceeds two, each line will be terminated with a circuit breaker. A maximum of four 69kV lines will be terminated at a station (Reference paragraph 1.7 on 3 terminal lines in the Guidelines for Electric System Planning).

1.5.3 Max # Transformers: A maximum of four 15/20/25-28 MVA 45 C-55 C

69/12kV transformers will typically be installed to serve a 4 square mile area of 60-75MW. Most substations will likely require only 2 transformers to serve a four square mile area @ 15MW/sqmi.

Initial construction should only include two 69kV bays in most cases unless 3-69kV lines are required for line loading considerations.

1.5.4 Looped Service:-Industrial substations (both 69kV & 115kV) will be

provided looped service if the customer agrees to pay the approximate facilities charge. Facilities additions for 69kV & 115kV industrial substations are determined contractually and will be resolved on a case-by-case basis.

New residential 69kV stations will initially be provided either radial/tapped 69kV service OR looped 69kV line service as determined after evaluation on a case-by-case basis in the "Load Growth" portion of the budget process. Looped service will be selected only after consideration has been given to the reliability of the 69kV line proposed for providing the service, how soon a 2nd bay or a 3rd 69kV line termination will be needed at the sub, the potential for frequent future construction outages for road widening etc., sensitivity or criticality of the customers served by the new sub, 12kV backup which will be available for the new sub and other issues as appropriate. Irrespective of the outcome TSP will document and distribute the results of their evaluation to the Budget Prioritization Process Team membership.

If radial/tapped service is selected as the preferred option, the looped service alternative with associated incremental cost will also be automatically introduced in the "Distribution Operational Reliability"

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STANDARD PRACTICES DOCUMENT portion of the budget process. As a result of this, the question of radial/tapped vs looped service for the new residential sub will be entertained once again as part of the budget prioritization process.

Note: Once the final decision has been made to provide looped rather than radial service to a new residential sub the new sub will be constructed with only 2 bays.

1.5.5 Drops: All 69kV line drops will be single 954 ACSS at the time of initial

construction.

1.5.6 Bus/Bay Ampacity: Initial distribution substation 69kV bus and bay design shall be 2000 amperes.

1.5.7 Bus Ampacity Upgrade: When a portion of a 69kV bus must be

upgraded, rebuilding the entire bus to current design standards should be evaluated on a case by case basis. When other significant construction work is planned for a substation, upgrading the entire 69kV bus to current design standards should be evaluated. Factors to be considered shall include the future bus ampacity requirements and the consequences of doing this work at a future time.

1.5.8 Low Profile Reconstruction: By joint decision, Transmission System

Planning, System Planning & Performance and System Design & Construction will choose which existing substation should be converted from high to low profile. These are substations where a separately justified job caused an immediate or long term problem with the existing structure. The conversion to low profile will be done along with the job which initiated the action.

1.5.9 Mobile Connection: New substations should have a connection point

for a mobile substation when feasible. A mobile connection will be added to existing substations where feasible when significant other construction is planned.

1.5.10 Transformer Addition vs New Substation: When the load in a new

substation area exceeds 7MW, consideration will be given to the relative merits of opening a new 69/12kV distribution substation versus adding a transformer to an existing 69/12kV distribution substation.

1.5.11 Bus Configuration: The standard 69kV bus configuration is described

in Figure 2 in Section 7.0. Non-standard 69kV bus configurations are analyzed to determine which option will provide the best system to meet individual industrial customer needs.

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1.5.12 Short Circuit Duty: The new standard for 69kV circuit breakers is 44kA.

1.5.13 LOAD BREAK SWITCHES: On a case-by-case basis Load Break

Switches at substations will be equipped with supervisory controlled MOD's. In making this decision consideration will be given to geographic location of the sub, sensitivity of the load served in the area and whether or not the switches isolate islands.

1.6 12kV facilities at a 69/12kV Distribution Station

1.6.1 Distribution Circuits: A maximum of five 12.47kV feeders may be

served by one 28.0 MVA transformer.

1.6.2 12kV Circuits: The 12.47kV circuits are three phase, four wire, grounded wye configuration.

1.6.3 12kV Ties: The 12.47kV feeders are open looped radial and when

connected to adjacent feeders, are typically connected through manually operated switches which are locked open during normal operation.

1.6.4 Feeder Ampacity: Maximum feeder capacity is 600 amperes (13MVA) but

may be constrained due to feeder get away heat limitations. Maximum normal operating current will be limited to that value defined at, see: \\srp.gov\corpdocs\ElecSyEngStandards\Files\Ratings Summary\RatingsSum.pdf

for overhead and for underground information (Table 4).

1.6.6 Feeder Transfer Bus: New 69/12kV substations will be built to accommodate a 600 amp feeder transfer bus. New transformers added at existing stations will be constructed to include the 600 amp feeder transfer capability with existing 12kV feeders at the station.

2.0 TRANSFORMERS:

2.1 500/230kV Transformers: -Nameplate ratings shall be 320/427/533-598 MVA 45 °C – 55 °C, 525/230 kV. -Nominal positive sequence impedance shall be 6.5% on a 320 MVA base. -A 500kV BIL of 1425kV; a 230kV BIL of 825kV. - A maximum emergency loading of 100% of the emergency limit specified in Transmission/Generation Transformer Loading Limit s Document located in Substation Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

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2.2 230/115kV Transformers: -Nameplate ratings shall be 100/133/167-187 MVA 45 °C – 55 °C, 230/115 kV. -A nominal positive s equence impedance of 6% on the botto m nameplate rating (161 MVA or other rating as determined). -A 230kV BIL of 825kV; a 115kV BIL of 550kV. - A maximum emergency loading of 100% of the emergency limit specified in Transmission/Generation Transformer Loading Limits Document located in the Substation Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

2.3 230/69kV Transformers: -A nameplate rating of 100/133/167-187 MVA or 150/ 200/250-280 MVA 45 C-55 C. -A minimum positive sequenc e impedance of 6.00% (12% at stations with generation) on a 100 MVA base, 9.00% on a 150 MVA base. -A 230kV BIL of 825kV; a 69kV BIL of 350kV. -A maximum emergency loading of 100% of the limit specified in Transmission/Generation Transformer Loading Limits Document located in Substation Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

2.4 69/12kV Transformers:

-A nameplate rating of 15/20/25-28 MVA 45 °C – 55 °C with a +/- 10% reduced capacity load tap changer (LTC) in the secondary winding. -A nominal positive sequence impedance of 7.5% on a 15 MVA base. -A 69kV BIL of 350kV; a 12kV BIL of 110kV. -The station design shall limit the maximum distribution substation transformer loading under normal conditions to 90% of nameplate capacity to allow for loading under contingency conditions. - The station design shall limit the maximum emergency distribution substation transformer loading of 69/12 kV transformers to the value determined by System Planning & Performance) which historically has been about 125% of their highest nameplate rating under contingency loading conditions. - The station design shall limit the maximum industrial substation transformer loading of 69/12 kV transformers to 100% of their highest nameplate rating under any operating conditions.

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3.0 CIRCUIT BREAKERS, CIRCUIT SWITCHES & TRANSFORMER PROTECTORS

3.1 500kV Circuit Breakers: A minimum continuous current rating of 2000

amperes.-Symmetrical interrupting current (IC) ratings of 40 kAIC or 63 kAIC as required.

3.2 230kV Circuit Breakers: Continuous current ratings of 2,000 or 3,000

amperes depending upon the ultimate station requirements. Symmetrical interrupting current (IC) ratings of 50 kAIC.

3.3 115kV Circuit Breakers: A continuous current rating of 2000 amperes-

Symmetrical interrupting current (IC) ratings of 40 kAIC

3.4 69kV Circuit Breakers at Receiving Stations: Continuous current ratings of 3000 amperes. Symmetrical interrupting current (IC) rating of 44 kAIC

3.5 69kV Circuit Breakers at Distribution Stations: Continuous current ratings

of 2,000 amperes. Symmetrical interrupting current (IC) ratings of 40 kAIC minimum.

3.6 69kV Transformer Protectors: Be installed in new substation installations.

Transformer protectors will be installed in existing substation bays where a need is demonstrated and the work can be scheduled. Have symmetrical interrupting current (IC) ratings >20 kAIC

3.7 12kV Circuit Breakers: A continuous current rating of 1200 A, 2000 A or 3000

A as required. 1200 A and 2000 A breakers shall be rated for 20 kAIC. 3000 A breakers shall be rated for 25 kAIC. A nominal voltage rating of 13.8kV. (21) The new 12kV metal clad switchgear units shall have 5-12kV circuit breakers for feeders.

3.8 12kV Circuit Switches: 12kV circuit switches are used to isolate or

sectionalize loads between operational zones for planned and emergency system switching. New overhead and underground switches should be the gang operated load break type. Gang-operated air break switches should be used between all major feeder ties and for "Normally Open" switches between radial feeders. Blade disconnect switches may be used for parallel switching between feeders within the same 69kV area or to isolate specific loads. -Current ratings for 12kV switches are found in Disconnect Switches AK01.02 part of Substation Design Standards at: http://insidesrp/elsyseng/electricsys/substd.html

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4.0 COMPENSATION, SHUNT & SERIES 4.1 500kV

4.1.1 Shunt Compensation: 500kV line reactors will be used to control open

end line voltages and provide voltage control. A load break switching device should be installed on line reactors intended for use in controlling system voltage. This will be studied on a case-by-case basis. Tertiary windings of EHV transformers may be used as required for shunt capacitors and reactors for voltage control. Nominal shunt reactor size is 50 MVAR.

4.1.2 Series Compensation: Series capacitors may be used on EHV lines to

provide for power system stability, power flow distribution and voltage support. An SSR evaluation may be conducted when a series capacitor addition is proposed.

Series Capacitors shall be sized so that as a minimum they can accommodate continuously the maximum power flow for the worst case single contingency outage plus 10 percent margin. The margin is added to compensate for the possibility of capacitor cans out of service. This will result in the series capacitors not being loaded beyond 90% of their continuous emergency limit.

4.2 230kV: 230kV shunt capacitor bank will be considered for improving the

voltage profile on the transmission system . (Requirements for Shunt Capacitor Banks AK09.01 located in Substation Design Standards at: http://insidesrp/elsyseng/electricsys/SubStd.html)

4.3 115kV: 115kV shunt capacitor banks will be considered for improving the voltage profile on the transmission system . (Requirements for Shunt Capacitor Banks AK09.01located in Substation Design Standards at:

http://insidesrp/elsyseng/electricsys/SubStd.html)

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STANDARD PRACTICES DOCUMENT 4.4 69kV: 69kV shunt capacitor banks will be considered for improving the voltage

profile on the subtransmission system. (Requirements for Shunt Capacitor Banks AK09.01located in Substation Design Standards at: http://insidesrp/elsyseng/electricsys/SubStd.html)

4.5 12kV: Distribution shunt capacitors are planned for:

12kV distribution feeders to compensate for reactive power consumed by customer loads. 12kV substation busses to compensate for the reactive power consumed by the station transformer. Sufficient capacitors should be installed to provide unity power factor at peak load on the 69kV bus (see paragraph 2.1.5 in the Guidelines document). (Requirements for Shunt Capacitor Banks AK09.01 located in Substation Design Standards at: http://insidesrp/elsyseng/electricsys/substd.html)

4.6 Industrial Customers

Shunt Compensation will be required of large industrial customers to improve the power factor to 0.85 as defined in SRP's Rules & Regulations. http://www.srpnet.com/about/rulesregs.aspx

5.0 TRANSMISSION LINES & 12kV FEEDERS:

5.1 500kV Transmission Lines: The normal conductor size is 2156 MCM (bluebird). Other factors may require a different wire size which will be evaluated on a case by case basis. Single circuit steel tower or steel pole structures (Transmission line requirements for 500kV lines will be determined on an individual basis).

5.2 230kV Transmission Lines: The normal conductor size is 954 MCM. Other

factors may require a different wire size which will be evaluated on a case by case basis. Bundled ACSR or single conductor ACSS as dictated by a loss evaluation.230kV line structures will be double circuit steel towers, steel poles or wood structures.

5.3 115kV Transmission Lines: The normal conductor size is 795 MCM. Other

factors may require a different wire size, which will be evaluated on a case-by-case basis. 115kV line structures will be steel towers, steel poles or wood structures.

5.4 69kV Transmission Lines: The standard conductor for new 69kV line

construction is 954 MCM ACSS. -Existing single conductor 795 MCM 69kV lines will be upgraded with a single 954 MCM ACSS conductor as required for capacity.

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STANDARD PRACTICES DOCUMENT New line extensions from existing single conductor 795 MCM lines will be 954 MCM ACSS. The standard conductor for new URD 69kV line construction is 1500 MCM copper. This will only be considered when requested and paid for by the customer 69kV line structures will typically be wood poles and may accommodate double 69kV circuits if the lines are serving different 230kV receiving station areas or independent loops within a 230kV receiving station area. If loop service to a distribution station is accomplished with a double circuit, single pole line; steel poles should be used. Line K-P-F or similar disconnect switches shall be removed and replaced by load-break station disconnect switches when a 69kV line is upgraded. The continuous overload capability of K-P-F or similar disconnect switches will be as listed in the Line & Equipment Rating Summary Documents: Table 6 \\srp.gov\corpdocs\ElecSyEng Standards\Files\Ratings Summary\RatingsSum.pdf For summer emergency rating, the ambient is assumed to be 45 C.

5.5 12kV Feeders

Conductor size for new overhead primary feeders will be 397 MCM AA. The continuous overload capab ility of K-P-F or similar disconnec t switches for overhead primary feeder s will be as listed in the Line & Equipment Rating Summary Documents, see link: Table 6 \\srp.gov\corpdocs\ElecSyEngStandards\Files\Ratings Summary\RatingsSum.pdf For summer emergency rating, the ambient is assumed to be 45 C. (13) Conductor size for new underground primary feeder will be 750 MCM AA. Two overhead 12kV feeders may be placed on common structures only if the circuits are from independent transfo rmers except for new substations. http://insidesrp/elsyseng/electricsys/Distribution/Distribution_Design.htm

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STANDARD PRACTICES DOCUMENT 6.0 DEFINITIONS

Breaker-and-a-half Bus Configuration: A substation bus configuration where two elements (lines or transformers) are termi nated in each cross bay using 3 circuit breakers (see Figure 1C in Section 7.0). Double Breaker Bus Configuration: A substation bus configur ation where each of the elements in the substation (lines or transformers) is terminated separately between two breakers which are each tied to a main bus (see Figure 1C in Section 7.0). Feed, Looped: When a substation is provided with 2 or more sources of power, which are both (or all) normally closed, it is said to have looped feed or looped service. Since both sources are normally clos ed there is pot ential for flow through of power across the substation bus. Feed, Radial: When a substation is provided with only 1 source of powe r it is sa id to have a radial feed or radial service. With radial service the lo ss of the single feed causes loss of load which mu st be restored via switching on the substation feeders if available. Feed, Tapped: A special form of radial feed where the source for a sub is created by attaching a line to an existing line in "T" fashion as opposed to routing the existing line in and out of the sub (Looped Feed) or terminating the new feed at an existing sub. Feed, Dual: When a substation is provided with 2 or more sources of power only one of which is normally closed it is said to hav e a dual feed. If the normally clos ed source of power t o the sub is lost, ser vice to the sub must be restored by s witching the normally closed source open and closing the normally open source. This may be done manually either locally or remotely if the substation is so equipped.

Paired Element Bus Configuration: A substation bus configuration where two elements (line plus transformer) form a series combination with no a utomatic sectionalizing device separating them such that a fault on either one causes both to be removed from service. Ring Bus Configuration: A substation bus configuration where each of the elements in the substation (lines or transforme rs) are terminated separ ately between two breakers, which are tied together forming a ring (see Figure 1C in Section 7.0). Zig-Zag Bus Configuration: A substation bus configuration resembling a Double Breaker configuration but with breakers missing resulting in some elements being tied to the main bus through only a single breaker. (See Figure 2C, in Section 7.0).

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STANDARD PRACTICES DOCUMENT 7.0 FIGURES & TABLES Figure 1C Ring Bus Configuration Figure 2 Standard 69kV Bus Configuration Figure 2C Zig-Zag Bus Configuration

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT 1.0 OPERATING STUDIES (69KV & ABOVE) ................................................. 52

1.2 Study Areas ..................................................................................... 52 1.3 Contingency Analysis....................................................................... 53 1.4 Problem Resolution.......................................................................... 53 1.5 Planning Study Impact ..................................................................... 53

2.0 CONSTRUCTION OUTAGE STUDIES (69KV & ABOVE) ......................... 54

2.1 Base Cases .........…......................................................................... 54 2.2 Contingency Analysis.....................................................................… 54 2.3 Problem Resolution........................................................................... 55

3.0 SUMMER SWITCHING STUDIES (12KV) .............................................. 55

3.1 Study Case….................................................................................... 56 3.2 New Construction Added .................................................................. 56 3.3 Guidelines For N-0 Studies............................................................... 56 3.4 Study ................................................................................................ 56 3.5 Study Timing..................................................................................... 56 3.6 Single Contingency Studies.............................................................. 57

4.0 69/12kv TRANSFORMER & 12kv BREAKER MAINTENANCE ................. 57 5.0 12 KV AUTOMATED SWITCHING TECHNOLOGY.................................... 58 6.0 FIGURES & TABLES .................................................................................. 59

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT Transmission System Planning conducts 4 types of studies for Power Operations on a routine basis. These studies are called Operating Studies, Construction Outages Studies, Breaker Out for Maintenance (BOM) Studies and 12kV Seasonal Switching Studies. Since BOM Studies are conducted infrequently on an "as requested" basis they are not discussed in this section of the guidelines document. The following paragraphs discuss the procedure and assumptions associated with the other three types of studies. 1.0 OPERATING STUDIES (69kV & ABOVE)

Operating studies are done annually on a joint basis with APS and WAPA. The base case used in the analysis is coordinated between the three utilities and used by each in studying their particular portion of the system. SRP uses the following procedure/assumptions to conduct the operating study on its portion of the network. 1.1 Base Cases

1.1.1 Loads- Forecasted peak load is modeled for the coming summer

season and winter season (for those areas where winter load is more severe than summer load).

1.1.2 Circuitry- Construction projects, which are expected to be completed

before May 31, are modeled in the case as though completed. Sensitivities are run to test the effect of the possible delay of projects whose expected date for completion may slip beyond May 31.

1.1.3 Generation- An economic generation pattern is assumed for the base

case. Sensitivities are run as a part of the study to determine the impact of generation extremes.

1.1.4 Ratings- Line and transformer ratings used in the power flow model

are the same as those used in the planning process. The relationship between these planning type ratings and the alarm levels used in the EMS to alert PDO of problems are outlined in Table A in Section 6.0.

1.2 Study Areas

1.2.1 Without Generation- Load levels for an area are compared to the

previous year's. Those areas with significant growth are considered for study.

1.2.2 With Generation- Areas with generation are studied regardless of

growth.

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT 1.3 Contingency Analysis

1.3.1 Single Contingencies- Outages will be studied for each 69kV, 115kV,

230kV and 500kV line as well as each 230/69kV, 230/115kV and 500/230kV transformer. Line loadings in excess of their emergency ratings, transformer loadings in excess of their emergency rating, and 69 & 115kV bus voltages which fall below the acceptable minimum level (as determined by the Subvolt) will be identified and operating solutions will be explored.

1.3.2 Multiple Contingencies- Outages of 69kV bus sections at 230/69kV

receiving stations as well as 115kV and above tower outages, common corridor outages and stuck breaker outages will be studied. Line and transformer overloads and voltage problems resulting from the multiple 115kV and above outages will be identified and solutions that include generation tripping and load shedding will be provided.

1.4 Problem Resolution

1.4.1 69 & 115kV Switching- Line and transformer overload problems will be

resolved with temporary switching solutions where ever possible. This solution is preferred because of the relative low cost.

1.4.2 Uneconomical generation- When a switching solution is not feasible

an uneconomical generation pattern should be explored to resolve line/transformer overload problems.

1.4.3 Load shedding- When all else fails load shedding solutions will be

explored to resolve overload problems. Non-firm load will be shed first. If necessary, firm load may be shed also.

1.4.4 Line Overloads- When during the course of an operating study a

potential line overload problem is discovered, Line Design will be requested to validate the thermal rating for the line in question considering actual field conditions (i.e. minimum tree, line crossing and 12kV underbuilt clearance). This could result in a customized rating either less than or greater than the generic rating for the line. In either case the new rating will become the official rating used in future planning and operating studies.

1.5 Planning Study Impact

Output of the operating study serves as input to the planning studies. Problems discovered as part of the operating study verify the need for long term solutions identified in the planning process.

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT 2.0 CONSTRUCTION OUTAGE STUDIES (69kV & ABOVE)

Construction Outage Studies are conducted by Transmission System Planning throughout the year on an as needed basis.

2.1 Base Cases

2.1.1 Loads: Forecasted peak load is modeled using the historical patterns of

the load for the period being studied. In addition, current load behavior, as well as estimated increase due to new customers, is added to the forecast.

2.1.2 Circuitry: Construction projects which are expected to be completed

before the construction period being studied are modeled in the case as though completed.

2.1.3 Generation: An economic generation pattern is assumed for the base

case. Sensitivities are run as a part of the study to determine the impact of generation extremes. Known long term generation outages are included in these construction outage studies.

2.1.4 Duration & Sequencing: Details regarding the duration and sequence

of events for each individual construction outage are ascertain via meetings/communication with the operations department.

2.2 Contingency Analysis

2.2.1 Single Contingencies- Outages will be studied for each 69kV, 115kV

230kV and 500kV line as well as each 230/69kV, 230/115kV and 500/230kV transformer in the areas where the particular construction project of interest will occur. Line and transformer loadings in excess of their emergency seasonal rating and 69 & 115kV bus voltages which fall below the acceptable min level (as determined by the Subvolt) will be identified and operating solutions will be explored.

2.2.2 Multiple Contingencies- In the area where the particular construction

project of interest will occur outages of 69kV bus sections at 230/69kV receiving stations will be studied. Line and transformer overloads and voltage problems resulting from these outages will be identified and operating solutions will be explored.

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2.3 Problem Resolution

2.3.1 Shifting Seasons- Scheduling construction during seasons of the year when load is at its minimum is effective in most instances.

2.3.2 69kV Switching- Line and transformer overload problems and voltage

problems should be resolved with temporary switching solutions wherever possible. This solution is preferred because of the relative low cost.

2.3.3 12kV Load Transfer- Distribution load will be shifted from one feeder to

another to relieve overload problems where appropriate.

2.3.4 Uneconomical Generation- When shifting seasons, 69kV switching and 12kV load transfer are not appropriate an uneconomical generation pattern should be explored to resolve line/transformer overload problems and voltage problems.

2.3.5 Nomograms- An effective graphical method for communicating the

conditions under which uneconomical generation or season shifting can resolve constructions outage problems is the nomogram (see Figure 2). The nomogram is a plot of load level versus generation in a particular area of the system. If actual conditions are such that the operating point (actual generation and actual load plotted on the graph) is in the "Safe Operating Region" on the nomogram the system will be free of problems. If the operating point is not in the "Safe Operating Region" on the graph, safe operation can be restored by adjusting generation or by rescheduling the construction outage until the load level drops such that the operating point returns to "Safe Operating Region".

2.3.6 Mobile 69/12kV Transformer- Certain construction outages may require

the use of the 69/12kV mobile transformer to maintain continuity of service.

3.0 SUMMER SWITCHING STUDIES (12kV)

System Planning & Performance conducts summer switching studies for Electric System Operations each year. The goal of the studies is to locate heavily loaded 12kV circuits and 69/12kV transformers before the peak summer season and recommend switching procedures to resolve the loading issues on the circuits and bays. These studies provide advance indication of heavy loading on electrical facilities, provide opportunities to equalize the loading and/or identify additional construction that may be required to alleviate overloads in the future.

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT 3.1 Study Case

The study case is developed from a base case containing actual loading experienced on the system the previous year. New growth that is anticipated to be in-service is then added to the base case as well as any weather adjustment that might be necessary to reflect peak loading conditions during the upcoming peak season.

3.2 New Construction Added

New substation transformer additions and other new 12kV feeder work are added to reflect the system that will be in-service during the upcoming peak load season.

3.3 Guidelines For n-0 Studies

3.3.1 Substation transformers are typically loaded to a maximum

level of 85% of the emergency rating. (This access database is located in the Substations Equipment Database at: http://insidesrp/elsyseng/electricsys/SubEquip.html

3.3.2 Feeders are loaded to roughly 70% of the emergency loading limit for the

feeder conductor. Historically, this has been assumed to be 70% of 430 amps which was the emergency rating for 500 MCM getaways in-duct. This rating has recently been revised for both 500 MCM and 750 MCM cables. See Table 2 located in the following link: http://insidesrp/elsyseng/electricsys/SubEquip.html Table 2

3.3.3 Normal opens should be avoided at blade disconnects, non- unitized pole

risers and live front underground switches.

3.4 Study

Where loading on the circuits/bays exceeds the guidelines, switching to lower loaded bays/circuits is recommended using normal open switches. In some cases the loading level cannot be reduced to an acceptable level due to a lack of connections between the heavily loaded equipment and lightly loaded equipment. When this occurs, some new construction of 12kV feeder ties and/or switches may be requested in the area. Typically this construction cannot be completed before the upcoming peak season. For extreme guideline violations, some construction may be completed by the upcoming peak season.

3.5 Study Timing

The summer switching study completion date is May 1

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3.6 Single Contingency Studies

In critical areas, single contingency studies may be performed by System Planning & Performance to determine if significant switching would be required during peak loading conditions if an outage of a 69/12kV transformer were to occur. Loading to 100% of the emergency rating for lines and transformers is allowed during contingency conditions. Study timing may coincide with N-0 study work or may be requested on a case by case basis.

3.6.1 Switching Status Changes: If more than 20 switch status changes are

required to pick up the load, some additional 12kV construction and/or 69/12kV transformer capacity may be needed in the area. In general, the 20 switch status changes represent a threshold at which double tiered switching may be required, i.e., unload a backup circuit or bay so that margin is then available to pickup the load that is out. Double tiered switching can result in a lengthy outage to the customers and therefore construction may be required to reduce the need for this level of switching.

3.6.2 Customer Downtime: The 20 switch status change requirement is based

on goals to restore residential service within 2 hours and commercial service within 2 hours following an outage.

3.6.3 Use of Mobile Transformer: A mobile transformer may be recommended

when the next contingency could cause loss of load. Mobile Transformers take 16-24 hours to install. It is therefore important to provide for backup 12kV ties to use until the Mobile Transformer can be energized. This is typically provided with the 85% transformer guideline and 70% feeder loading guideline.

4.0 69/12kV TRANSFORMER & 12kV BREAKER MAINTENANCE

To meet the customer downtime objectives identified in the seasonal switching section 3.6.2 above, maintenance may be allowed during peak loading conditions if sufficient capacity exists in the area to provide adequate service to customers. Otherwise, maintenance may be restricted to off-peak times. The general rule is that no more than one element can be out for maintenance in an area at any time.

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OPERATIONS SECTION OF PLANNING GUIDELINES DOCUMENT 5.0 12kV AUTOMATED SWITCHING TECHNOLOGY

Recent technology advancements have provided the opportunity to implement automated technology in the 12kV distribution system. This technology may provide SRP the opportunity to reduce margins while at the same time improve customer service. Some operational requirements for this technology are summarized below.

5.1 Visibility & Control: DOC requires visibility and control of these devices be

made available at the Electric System Operations center.

5.2 Adequate Backup Margin: For devices that automatically transfer the load t o an alternate source, adequate backup margin will need to be planned in t he alternate source.

5.3 Multiple Devices in the area: It is important to evaluate the location of these

devices so that two devices in the same area don't transfer to the same backup circuit.

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6.0 FIGURES & TABLES

TABLE A COMPARISON OF CURRENT PLANNING & OPERATING LOAD LIMITS*

TRANSFORMERS Planning PDO a) base loading (n-0) studies a) 1st alarm: 230/69: "Nameplate Rating” in 230/69: "Nameplate Rating" Transmission/Generation Transformer Loading Transmission/Generation Transformer Loading Limits Limits Database Database 69/12: 85% of "Emer. Limit” in 69/12: "Nominal" per Table 7b in Substation Transformers Substation Transformers database database others: highest nameplate rating others: 90% of top 65 deg C nameplate b) contingency (n-1) studies b) 2nd alarm 230/69: "Emergency Max Loading" 230/69: "Emergency Max Loading" summer/winter in summer/winter in Transmission/Generation Transformer Loading Transmission/Generation Transformer Loading Limits Database Limits Database 69/12: "Emer. Limit" in 69/12: "Emer. Limit” in Substation Transformers database Substation Transformers database others: highest nameplate rating others: 100% of top 65 deg C nameplate LINES, 69 TO 500kV Planning PDO a) n-0 studies: "Normal" summer/ a) 1st alarm: 90% of "Normal" summer/

winter rating per Table 1 winter rating per Table 1 b) n-1 studies: "Emer." summer/ b) 2nd alarm: 100% of "Normal" summer/

winter rating per Table 1 winter rating per Table 1 LINES, 12kV Planning DOC** overhead: Table 2 overhead: Table 2 underground: Table 3 underground: Table 3

alarms: 300A on 360A ckts 400A on 480A & 600A ckts

SUMMER VS WINTER Planning PDO Summer ratings are used in summer Summer ratings used when daily high temp

peaking areas > 95 deg F for 3 consecutive days Winter ratings are used in winter Winter ratings used when daily high temp peaking areas < 83 deg F for 3 consecutive days NOTES (1) Tables 1, 2, 3 are found in the Line & Equipment Ratings section of the Planning Guidelines Document (2) Transmission/Generation Transformer Loading Limits Document can be found @ Transmission/Generation Transformer Loading Limits Document located in Substation Equipment Database @ http://insidesrp/elsyseng/electricsys/SubEquip.html (3) Substation Transformers Database can be found in Substation Equipment Database @ http://insidesrp/elsyseng/electricsys/SubEquip.html ** 12kV feeder Time Phase Overcurrent relays are set at 360 Amps (older subs), 480 Amps or 600 Amps. The Time Phase Overcurrent relays are an upper "overload" limit on feeder phase current. DOC trys to keep feeder loading below the feeder overload alarm limit, except in emergencies or during cold load pickup. When feeder loading reaches 450 amps, DOC looks for a way to unload the feeder. In emergencies feeder loading can be over 450 amps, & even approach the Time Phase Overcurrent relay setting, if the only alternative is customer interruption.

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Figure 2 Example of a Nomogram - Generation vs. Load Level

0

2000

4000

6000

8000

10000

12000

14000

16000

0 150 345 765 1010 1115 1654 1850 1966 2220 2510 2945 3130

Generation (MW)

Lo

ad (

MW

)

Safe Operating Region

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SRP ELECTRIC SYSTEM

LINE AND EQUIPMENT RATINGS

For information regarding the Line and Equipment Ratings please use the link below.

\\srp.gov\corpdocs\ElecSyEng Standards\Files\Ratings Summary\RatingsSum.pdf

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