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A Feasibility Study on Connecting Two 57 MVA,LM6000 Gas Turbine Generator Sets atSpringdale Substation
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A Feasibility Study on Connecting Two 57 MVA, LM6000 Gas Turbine Generator Sets at
Springdale Substation
August 1999 Prepared by Allegheny Power's Operations Planning Section of the System Planning and
Operations Business Unit
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Introduction and Background ___________________________________________________ 3
Project Description _____________________________________________________________ 4
Results _________________________________________________________________________ 5
Assumptions ____________________________________________________________________ 7
Study Methodology and Procedure ______________________________________________ 8
Short Circuit Studies ____________________________________________________________ 9
Stability Considerations ________________________________________________________ 10
APPENDIX A
APPENDIX B
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Introduction and Background Allegheny Energy Unit 1 and unit 2, LLC as agent for the unregulated generation business unit Energy Supply Division (ESD) has contacted System Planning and Operations on the feasibility of interconnecting two 57 MVA LM6000 Gas Turbine Generator sets (GT sets) to the Springdale Power Station 138 kV bus. The request was made to begin producing power and have the GT sets in-service by July 1, 1999. Since the original request was received, a delay in the delivery of materials that are required to complete the interconnection, and the need for air quality permits from Allegheny County, have delayed the in-service date to October 15, 1999.
Studies performed prior to 1996 indicated that Springdale could serve as a primary site to install Gas Combustion Turbine Generation, when and if Allegheny Power System (APS) ever decided to install such generation.
Beginning in 1996 the Federal Energy Regulatory Commission (FERC) issued
Rules 888 and 889. With these rulings came the advent of the Open Access Transmission Tariff (OATT) and the isolation within electric utilities of their generation from their transmission operations. Allegheny Power (AP) was no exception and beginning on January 1, 1996 AP had created business units designed for compliance with the FERC rulings.
To further complicate the issue, beginning on January 1, 1999 Pennsylvania
customers representing one-third of the West Penn Power load, and on January 2, 1999 two-thirds of the West Penn Power load were allowed to select an electric supplier other than West Penn Power Company. As a result, AP chose to unregulate a portion of the West Penn Power Company generation equivalent to that customer load. Allegheny created the ESD business unit to market the unregulated generation.
This document is a report prepared for Allegheny Energy Unit 1 and Unit 2, LLC
and ESD to address their request to interconnect two 57 MVA LM6000 GT sets at Springdale Substation.
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Project Description The concept is shown on the sketch on the following page. As indicated, the two 57 MVA GT sets would be located about 1000 ft from the Springdale 138 kV bus. Each generator would consist of 48 MW winter or 44 MW summer, gas combustion turbines operating at 0.85 power factor. The units are designated as peaking units and will probably operate during peak usage hours, approximately 2,000 hours per year per unit. Service to the units will be provided by a single 138 kV line terminating on a single 138 kV circuit breaker, and will include a 138 kV metering package. The destination of output from the generators has not been designated and, therefore, many assumptions were required in order to complete the study. They are listed in the next section.
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DRAWN
SCALE
AUTHORIZATION
CHKD
SOURCE
REVIEWED
APPROVED
DATE
PLAN N
UM
BER
RE
V
NS
T. V. SPENCER
SPRINGDALE SUBSTATION
ARNOLD SERVICE CENTER
8-25-99P. L. ZAWELENSKY
INSTALL 138 kV BREAKER AND METER TO
CAD FILE
SPRINGDALENUG.PPTP L A N
PowerAllegheny
10/15/99
99-x-W
INTERCONNECT WITH NON UTILITY GENERATION
SPRINGDALE
GOBAIN
WPPCODLCO
138 kV
CHESWICK
YARD TOWER
YARD TOWER
HARWICK
STRUCTURESCROSSING
FEDERAL ST.
WHITE VALLEY
HUNT
INGD
ONYU
KON
RIV
ER
N.O.
KITTANNING
NO.1A
KISKI VALLEY
RIVER-
STRUCTURECROSSING
RIVER-
STRUCTUREHILL
138 kV
NUG
INSTALL A 138 kV BREAKER AND 138 kV METER
WP
PC
O
CU
STO
ME
R
1000 ft
FIGURE NO. 1
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Results The Feasibility Study (FS) results indicate that AP can accommodate the Allegheny Energy Unit 1 and Unit 2, LLC\ESD request for interconnection of two 57 MVA LM6000 GT sets.
Both power flow and short circuit studies indicate that the installation has no detrimental effect on the AP transmission system. However, Allegheny Energy Unit 1 and Unit 2, LLC and ESD need to be aware that in the event that there is congestion on the Eastern Interconnection, generation dispatch out of Springdale at times might be restricted. In that case, AP will follow the North American Electric Reliability Council's (NERC) Transmission Line Loading Relief Procedure (TLR) and the guidelines set forth within that procedure. A copy of this procedure can be downloaded via the Internet from the NERC website at http://www.nerc.com. Additionally, Allegheny Energy Unit 1 and Unit 2, LLC or ESD may choose to implement the NERC Market Re-dispatch or the AP Security Coordinator might implement the Lake Erie Emergency Re-dispatch (LEER) procedures that may require the units at Springdale to operate. Allegheny Energy (AE) has incorporated these procedures in its Open Access Transmission Tariff (OATT). More information on the NERC market re-dispatch procedure can be obtained from the NERC website at http://www.nerc.com. Information on the LEER can be obtained from your company’s representative to the Lake Erie Security Process committee, or from the FERC-filed LEER proposal.
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Assumptions All future studies require assumptions concerning the control area load, facility additions and transmission sales. This analysis is no exception. The most recent System models, the 1998 series, from the base case database for the 1999 summer, 2003 summer and 2008 summer seasons were selected as those to be tested. AP control area loads in those models ranged from 7,200 MW in the 1999 summer model to more than 8,000 MW in the 2008 summer model. Facility additions were assumed to be those as planned in the 1998 series of cases that followed the 1998-planning guide. Note that during the period studied there is no expectation that the existing Springdale Units 7 & 8 will be reenergized; so they were not modeled in this analysis. A quick review of data indicates that AP, PJM, FE and DQE plan no major facility additions. However, AEP and VP are planning to install major system additions in the Appalachian Power Company Area of AEP and the northern area of Virginia Power Company. Those planned facilities are modeled in the 2008 summer model but not in the 1999 summer or the 2003 model. Transmission sales modeled for those years are those included in the summer base case models and include only confirmed firm service reservations. The destination of the power output from the proposed GT sets at Springdale is unknown. Therefore, several transfer scenarios were assumed. Output from the GT sets was assumed to stay within the AP control area, or alternatively to be sold off-system to the west or to the east. Those additional tests modeling the output from the Springdale site to the east assumed the power was being sold to PJM, while those that took the power west modeled a transfer into DQE.
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Study Methodology and Procedure The in-service date for the gas turbine project is tentatively set for October 1, 1999. As a result, power flow study models were selected and completed for the years 1999, 2003 and 2008. The assumptions listed above for forecasted control area loads, maintenance schedules, confirmed Firm Point-To-Point Transmission reservations and generation dispatch, were all used during the analysis.
The destination of the power output from the proposed GT sets at Springdale is unknown. Therefore several transfer scenarios were assumed. Output from the GT sets was assumed to stay within the AP control area, or alternatively to be sold off-system to the west or to the east. Those additional tests modeling the output from the Springdale site to the east assumed the power was being sold to PJM, while those that took the power west modeled a transfer into DQE.
Power flow cases were created and contingency tests were evaluated based
upon the AP planning criteria reported in FERC Form 715 Part 4 (See Appendix A). These criteria were applied to studies using the current years model, as well as those using the 2003 and 2008 models, in order to evaluate the long-term effect the power output from Springdale might have on the AP transmission system in and around the Springdale site. If required, additional study work was to be performed to determine what if any limiting facility would require system upgrades to accommodate the installation of the GT sets.
Prior to 1999, Springdale had two generators that were included in the AP
Integrated Resource Plan. Total capacity of Springdale Units 7 and 8 was 207 MW. The proposed GT sets together totaled 114 MVA at an 85 % power factor, or about 96 MW. The studies looked for adverse loading due to the proposed installation and unit output, and its effect on system transfer capability.
In all, fourteen transfer test scenarios were completed and analyzed. Results of
the single contingency tests concluded that with the Springdale (AP)-Cheswick (DQE) 138 kV tie open, which is a normal operating situation, the installation had little effect on the 138 kV lines in the study area. If the tie were closed, the 138 kV tie-line was the thermal limit to regional and inter-regional transfers as well as intra-regional transfers, regardless of whether the proposed GT sets were in-service or not. Therefore, it is recommended that the operating practice of allowing the Springdale (AP)-Cheswick (DQE) 138 kV tie line to be operated normally open should remain in effect for the foreseeable future.
Although the proposed generation addition is small and the effect it has on
system transfer capability is minimal with the operating procedure in place, the effect on system losses was also considered. Power flow evaluations indicate that with the two GT sets at Springdale dispatched at maximum output the AP system losses are reduced by two MW.
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Short Circuit Studies
Results of the short circuit evaluation are tabulated below. The fault current values determined in the study indicate that the substation equipment at Springdale and neighboring substations is adequate, and that the addition of two 71.2 MVA** GT sets at Springdale will not cause any of the equipment to exceed short circuit ratings.
JUNE 1999 SYSTEM CONDITIONS CHESWICK–SPRINGDALE 138 kV LINE IN SERVICE 2@36/48/60 MVA, 138/13.8 kV Transformer(Z1=10%,Z0=8.5% @36 MVA)
BASE CONDITIONS (Without the new CTs) (3-phase symmetrical faults)
(With the new CTs) Z1=12.4% @71.2 MVA Z2=16.6% @71.2 MVA Z0=9.0% @ 71.2MVA (3-phase symmetrical faults)
Springdale 138 kV
Three Phase Fault Phase to Ground Fault
35724 Amps ∠ -83.25° 27128 Amps ∠ -81.40°
37569 Amps ∠ -83.50° 27782 Amps ∠ -81.48°
Springdale (G1) 13.8 kV
Three Phase Fault Phase to Ground Fault
14453 Amps ∠ -87.17° 0 Amps ∠ 0°
38474 Amps ∠ -88.94° 80.0 Amps ∠ -0.15° *
Springdale (G2) 13.8 kV
Three Phase Fault Phase to Ground Fault
14453 Amps ∠ -87.17° 0 Amps ∠ 0°
38474 Amps ∠ -88.94° 80.0 Amps ∠ -0.15° *
* Note: It was assumed that a grounding resistor of 100 ohms is installed on generator neutral. **Note: The value used for the short circuit study (71.2 MVA) differs from the value used for the steady state power flow analysis (57 MVA). This is necessary because of differently sized equipment in the generation facilities.
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Stability Considerations The transmission system is designed so that generating units remain in
synchronism and that cascading outages do not occur for credible contingencies such as electrical faults or sudden network changes caused by fault clearing and line reclosings.
Transient stability simulations are made to assess expected performance of
generating units when the transmission network is subjected to severe disturbances. Test results are used to determine critical fault clearing times and the ability of the system to prevent cascading outages. They are also used to study the effectiveness of alternative transmission plans to optimize the system's transient performance. Since it is impossible to anticipate and test for all combinations of contingencies that could occur on an interconnected network, those cases judged to be less severe, using APS transient stability criteria as a guide, are not routinely tested.
There are also many areas of the system, which are considered strong enough to
support the proposed amounts of generation without the need for stability analysis. It may, therefore, be deemed unnecessary to perform any stability simulations and will be evaluated on a case by case assessment.
Transient stability testing was not done as part of this study because the Project
generators are relatively small and, therefore, should not cause stability concerns for any APS units.
When the proposed generating station is designed and dynamics data for turbine
generators are available, the Developer should perform a transient stability study to determine critical fault clearing times and effects of line reclosings on the transient stability of the Project units. In addition, any updated dynamic machine data should be forwarded to Allegheny Power.
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APPENDIX A-Part 4:FERC FORM 715
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FERC FORM NO. 715 PART 4 Transmission Planning Reliability Criteria Contents Page 1. Introduction....................................................................................................................................................... 4-3 2. Thermal and Voltage Criteria........................................................................................................................... 4-6
2.1 Transmission System Facility Ratings 2.2 Normal System Conditions 2.3 Single Contingency Testing 2.4 Double Contingency Testing 2.5 Multiple Contingency Testing 2.6 Reliability Coordination Plan (RCP) 2.7 NERC Transmission Line Loading Relief (TLR) Procedure 2.8 Reactive Power Requirements
3. System Stability Criteria ..................................................................................................................................4-13
3.1 System Normal Criteria 3.2 Line Out Criteria
4. Additional System Performance Criteria..........................................................................................................4-15
4.1 Transfer Capability 4.2 Fault Currents 4.3 Switching Surges 4.4 Power Quality
5. Line and Substation Configuration Criteria .....................................................................................................4-18
5.1 EHV (345 kV and up) 5.2 Area (100 kV to 230 kV)
Appendix A - ECAR Document No. 1 ....................................................................................................................4A-1 Appendix B - NERC Reliability Principles and Guides ..........................................................................................4B-1 Appendix C - Reliability Coordination Plan............................................................................................................4C-1 Appendix D - NERC Transfer Capability Definitions.............................................................................................4D-1 Appendix E - Voltage Flicker and Harmonic Distortion Limits.............................................................................. 4E-1
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1. INTRODUCTION
Bulk power planning and operating procedures consistently include reliability as one of the essential measures of system performance. AP meets the need to expand and upgrade its transmission system by developing plans using criteria that provide for continued reliable operation consistent with economic and regulatory constraints. This document presents the reliability criteria used by AP to expand and upgrade the bulk power system of lines and substations above 100 kV.
Transmission system expansion plans are developed with the goal of minimizing revenue requirements, which include both capital and operating costs while meeting planning criteria that deal with maintaining acceptable system performance. The proper application of transmission planning criteria requires substantial engineering judgment based upon numerous and extensive studies of the system by the planning engineer. Prudently managed utilities rely on their planning engineers' knowledge, experience, and judgment in applying the criteria to specific circumstances on the transmission system. For this reason, it is simply not possible to document all the criteria that may be used to decide the way in which a system is developed and expanded.
To understand reliability in system performance requires an understanding of how reliability affects a system. The primary reliability objectives are adequacy and security. They can be defined as follows:
Adequacy - which is the capacity to meet system demand within major component ratings in the presence of scheduled and unscheduled outage of generation and transmission components or facilities, and
Security - which is a system's capability to withstand system disturbances arising from faults and unscheduled removal of bulk power supply elements without further loss of facilities or cascading outages.
In order to evaluate the reliability of a system, it is necessary to have benchmarks or criteria to determine the levels of adequacy and security in a system.
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1. INTRODUCTION (continued)
The criteria in this document are based on AP and industrywide experience with equipment performance and acknowledges the need to provide operating flexibility for maintenance outages while limiting customer interruptions and the time required to restore service. Thus, various segments of the supply system will have increasingly stringent reliability criteria as one moves from lower to higher system voltages involving greater numbers of customers. Determination of the level of reliability that is acceptable depends upon what our customers are willing to pay for and ultimately upon the regulatory commissions and their decisions granting construction licenses and rate increases.
The following general planning objectives evolved and have been refined through years of experience to achieve the objectives of maintaining acceptable system performance through an adequate and secure system for the least cost. These objectives define the conditions under which a facility reinforcement would be added to the transmission system.
Χ The facility must represent an economical method to provide dependable service to our customers within
the constraints of regulatory, environmental, and political guidelines.
Χ The facility should be sized to meet growth needs according to the AP load forecast while providing an optimum level of reserve capability.
Χ The facility installation should be timed to maintain reliability and minimize cost.
Χ All feasible alternatives should be considered in planning a new facility. This includes, but is not
limited to, new technology, innovative applications of existing technology, controlling load growth, and automation of controls.
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1. INTRODUCTION (continued)
Interconnected transmission facilities, in addition to meeting AP criteria, must meet or exceed reliability criteria as established by the East Central Area Reliability Coordination Agreement (ECAR) Document No. 1 and the North American Electric Reliability Council (NERC) Planning Standards. These documents provide reliability criteria that are designed to test the ability of ECAR member systems to withstand certain contingencies without triggering a breakup and collapse of any major part of their bulk power supply network. ECAR Document No. 1 is included in these criteria as Appendix A and the NERC Reliability Principles and Guides as Appendix B.
Existing regulatory and environmental constraints such as the inability to obtain right-of-way can lead to conditions that do not meet our planning criteria. The degradation of reliability levels caused by these conditions must be recognized as such and not used as examples to justify subversion of reliability levels in other areas of the system.
The testing done on the transmission system is by mathematically modeling the system and solving the various simulated conditions on a computer using the power flow and transient stability programs.
The following represent the AP transmission planning criteria and are more fully discussed in Sections 2 through 5.
Χ Thermal and Voltage Criteria Χ System Stability Criteria Χ System Performance Criteria Χ Line and Substation Configuration Criteria
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2. THERMAL AND VOLTAGE CRITERIA
2.1 Transmission System Facility Ratings
Transmission line facilities within AP are rated for both summer and winter for continuous, 6-hour, and 2-hour periods of service while transformers use a one-hour, short-time emergency rating. The ratings make use of manufacturers' recommendations, industry standards, and in case of overhead conductor, a rating program by ECAR. The ratings that are developed take into account all of the elements which make up the facility including conductors, transformers, structures, terminal facilities, hardware, as well as relaying facilities and their settings, which protect the operation of the system.
AP uses a summer ambient temperature of 90ΕF (32.2ΕC), and winter ambient of 50ΕF (10ΕC). A continuous wind speed of two feet per second at a right angle to the conductor is assumed for both winter and summer ratings. The ratings needed to analyze the system are supplied as part of the power flow data.
2.2 Normal System Conditions
Normal system conditions are defined as all transmission and generation facilities in service except those known to be unavailable due to scheduled maintenance or a prolonged outage. All APS scheduled firm power sales and purchases with and between other systems are assumed to be in effect, as are outside inter-system transfers which impact the AP transmission system. Normal conditions for the seasonal operating base cases will differ somewhat from planning cases in that they will typically include some assumed non-firm economy sales in addition to firm sales.
Computer power flow system analyses are conducted for peak load conditions since that is the likely critical period for the transmission system.
The criteria for acceptable system performance for normal system conditions may include, but are not limited to: 2.2.1 Generation
All available generators are fully dispatchable to their normal seasonal operating capacity and can regulate to the scheduled voltage.
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2. THERMAL AND VOLTAGE CRITERIA (continued)
2.2 Normal System Conditions (continued)
2.2.2 EHV Transmission System (765 kV, 500 kV, and 345 kV lines and associated step-down substations)
All EHV system facilities operating within their normal (continuous) seasonal thermal capabilities, and within their normal voltage operating range of +10% to -2% of nominal voltage. Nominal voltages are 765 kV, 500 kV, and 345 kV.
2.2.3 Area Transmission System
(230 kV, 138 kV, and 115 kV lines and associated step-down substations)
All area transmission system facilities operating within their normal (continuous) seasonal thermal capabilities, and area transmission system voltages within +5% to -10% of nominal voltage for each voltage classification. Nominal voltages are 230 kV, 138 kV, and 115 kV.
2.3 Single Contingency Testing
A single contingency is the sudden outage of any single generation or transmission element (generator, line, or transformer) while performing a system function during normal system conditions.
The criteria for acceptable system performance during single contingency outages are as follows: 2.3.1 Generation and Interconnections
No generator output restrictions are caused by the contingency unless the generator or its associated facilities is the contingency element outaged. Generators and interconnections have sufficient capability to compensate for power loss until the loss can be restored by rescheduling internal generation or outside purchases can be arranged.
2.3.2 EHV Transmission System
All EHV transmission system lines remain within continuous seasonal thermal capability after any necessary system adjustments, and EHV transmission system voltages remain within 5% of their pre-contingency values.
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2. THERMAL AND VOLTAGE CRITERIA (continued)
2.3 Single Contingency (continued)
2.3.3 Area Transmission System
All area transmission line facilities are operating within their continuous seasonal loading capabilities. A six-hour seasonal rating is acceptable for transformer loading. This loading is limited to one six-hour period, after which the load on the transformer must be reduced to its continuous rating. Area transmission system voltages should remain within 10% of nominal and should not vary more than 10% from their pre-contingency level.
2.3.4 Customer Loads
No customer should be interrupted by the contingency unless directly connected to the outaged facility.
2.4 Double Contingency Testing
A double contingency is the outage of any combination of two lines, transformers, or generators. The outages may be simultaneous or sequential; however, the second outage occurs before system adjustments can be made. While the probability of a double contingency is less than a single contingency, the consequences, the effect on system reliability, can be much more severe.
The AP transmission system is designed to withstand the single contingency conditions described under Section 2.3. However, double contingency tests are also used to assess the strength of the system. If the double contingency tests indicate severe overloading or precipitous voltage drops that extend beyond the immediate area of the outage, then area reinforcement or system upgrading is considered.
2.5 Multiple Contingency Testing
Multiple contingencies are a combination outage of more than two lines, transformers, or generators. Such events are less probable than single or double contingencies, but because they are credible, multiple contingencies must be considered in any analysis of transmission system reliability to demonstrate the basic strength of a system. In some cases, it is the consequence of a multiple contingency testing that determines whether system reinforcements can be justified.
ECAR Document No. 1 (Appendix A) describes the criteria to be used for simulated testing of multiple contingency conditions. The Document No. 1 criteria are intended to assure that the ECAR bulk power supply network can survive and will not suffer cascading outages that could cause uncontrolled area-wide power interruptions during credible multiple contingencies. Since the AP operating companies are members of ECAR, the AP bulk power transmission system must be planned to withstand Document No. 1 criteria.
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2. THERMAL AND VOLTAGE CRITERIA (continued)
2.5 Multiple Contingency Testing (continued)
Multiple contingencies listed in ECAR Document No. 1 include, but are not limited to:
Χ Outage of transmission line, including double circuit tower line, when various generators are unavailable.
Χ Outage of substation, including loss of any directly connected generation.
Χ Sudden outage of a major load center.
Χ Outage of all lines on a common right-of-way.
2.6 Reliability Coordination Plan (RCP)
The AP EHV transmission system is firmly interconnected to neighboring systems by numerous tie lines at various voltage levels. These ties provide instantaneous mutual assistance for AP and its neighbors during emergency conditions but they can also allow the rapid spread of an electrical disturbance across system boundaries. Voluntary coordination of transmission planning activities among companies is essential to assure that reliable and economic operation can be maintained.
The RCP is a coordinated plan originally conceived and implemented by AP, PJM, and Virginia Power to assure that both thermal and voltage conditions on the interconnected system, specifically the AP-PJM-VP interface, are controlled to maintain reliable operation on the bulk power system. It is a plan for coordinated operation to control transfers across the interregional interfaces, but it is also applicable to future planning since it basically provides loading criteria in much the same way a thermal line rating would. The RCP is kept up to date by periodic reviews, which reflect any change in system configuration or schedules. The RCP is included in these criteria as Appendix C. In recent years the RCP was frequently invoked to shed transactions scheduled through AP’s network due to parallel flows caused by contract path schedules on other systems. NERC’s TLR procedure has provided the means for properly identifying transactions causing congestion and AP seldom experiences conditions requiring curtailments now. The RCP remains available as a local procedure for maintaining reliability.
2.7 NERC TLR
The FERC Transmission Line Loading Relief (TLR) procedure provides the means by which transfers can be controlled and or removed to maintain transmission system security. Substantial amounts of power continue to flow through the transmission system and are considered inadvertent flows caused by power transfers that are not contracted through the AP transmission system. With the implementation of the NERC TLR, AP has been able to seek relief during periods of heavy transfers but may
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have only limited control of these transfers for reliability considerations. 2. THERMAL AND VOLTAGE CRITERIA (continued)
2.8 Reactive Power Requirements
Although the primary function of the transmission system is the transport of real power (megawatts), the transmission planner must be cognizant of the equally important reactive power (megavars) requirements of the system. Without an adequate reactive power supply, the ability of the transmission system to carry real power may be severely limited. In extreme cases of deficient reactive power supply, rapidly deteriorating voltage conditions could trigger a cascading blackout over a wide area.
The reactive power sources commonly available to supply the reactive loads and losses include generators, the capacitive line charging component of lines, static capacitors, synchronous condensers, and static var compensators.
The following criteria generally describe the AP reactive planning philosophy:
2.8.1 System reactive compensation with adequate controls will be planned to supply the reactive
load and loss requirements of the system and to maintain acceptable voltage profiles as defined in Sections 2 and 3 of this chapter for:
2.8.1.1 Normal conditions.
2.8.1.2 Single contingency outage conditions.
2.8.2 Currently shunt capacitors are used in conjunction with generators and line
charging reactance to supply transmission system var requirements. Static var compensators and synchronous condensers may be used if instantaneous reactive response is required for widely varying var load and where their very high costs can be justified.
2.8.3 Each area or system should provide its own reactive load and reactive loss requirements
under normal operating conditions. 2.8.4 Switched capacitors should not cause more than a 3% voltage rise under normal conditions
with all facilities in service.
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3. SYSTEM STABILITY CRITERIA
The bulk power transmission system is designed to meet ECAR Document No. 1 criteria such that no uncontrolled cascading outages take place.
In addition, it is also designed so that the generating units remain in synchronism and all generator power swings are well damped following credible contingencies such as electrical faults and sudden network changes caused by fault clearing and successful or unsuccessful line reclosing. These criteria should be met for all operating load levels, taking due consideration for the relaying and automatic switching practices. The following criteria are used to test system stability:
3.1 System Normal Criteria
Generating units at any power output level before the disturbance should remain stable for the following tests of normal clearing:
3.1.1 A permanent three-phase or single-phase-to-ground fault on any line or transformer cleared by
the primary protective relaying scheme followed where applicable by an unsuccessful high speed reclosure for line faults.
3.1.2 Breaker failure: a permanent three-phase or single-phase-to-ground fault on any line or
transformer cleared by backup breakers due to the failure of the primary breaker to interrupt the fault.
3.1.3 Protective relaying overtrip: a permanent three-phase or single-phase-to-ground fault on any
line or transformer cleared by the primary protective relay and any adjacent line trip due to relaying overtrip followed where applicable by appropriate reclosings.
3.1.4 Primary protective relaying scheme inoperative: a permanent three-phase or single-phase-to-
ground fault on any line or transformer cleared by primary protective relaying at one end of the line, and backup or slower relaying at the other end.
3.2 Line Out Criteria
With one critical line or transformer out of service, and the system at peak load, generating units at any power output level before disturbance should remain stable for:
3.2.1 A permanent three-phase fault on any line or transformer cleared by primary protective
relaying scheme followed where applicable by an unsuccessful high speed reclosure for line faults except for a fault that separates a unit from the power system without an accompanying load island. Operating restrictions, such as limiting predisturbance real power output of a generator or generating station, may be considered for extraordinary situations to satisfy this criteria.
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4. ADDITIONAL SYSTEM PERFORMANCE CRITERIA
4.1 Transfer Capability
Transfer capability is used to assess and test the ability of the interconnected transmission network to move power between entities, companies, regions, subregions, pools, etc. Sufficient transfer capability is typically based on the ability to receive support from nonaffiliates during a generation capacity emergency.
The criteria used by AP were adopted from the NERC transfer capability definition as recommended in the NERC publication, "North American Electric Reliability Council Transmission Transfer Capability≅ (Appendix D). These criteria also are commonly used by interregional study groups such as the VACAR-ECAR-MAAC (VEM) and MAAC-ECAR-NPCC (MEN) study committees. The First Contingency Incremental Transfer Capability (FCITC) is defined by NERC as the power, incremental above base transfers, that can be transferred in a reliable manner under the following conditions:
4.1.1 With all transmission facilities in service, all facility loadings are within normal ratings, and all
voltages are within normal limits.
4.1.2 The bulk power system is capable of absorbing the dynamic power swings and remaining stable following a disturbance resulting in the loss of any single generation unit, transmission circuit, or transformer.
4.1.3 After the dynamic power swings following a disturbance resulting in the loss of any single
generating unit, transmission circuit, or transformer, but before operator-directed system adjustments are made, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits.
4.2 Fault Currents
Three-phase and single-line-to-ground short circuit currents and sequence voltages during faults are calculated for each bus on the transmission system. Fault current values are used to check the short circuit adequacy of equipment for system protection and protective coordination, and to determine electrical system strength at various locations on the system.
4.3 Switching Surges
Switching surge studies are performed to determine transient and dynamic overvoltages and circuit breaker recovery voltages during switching. These studies provide recommendations for switching devices and allowable switching sequences which limit overvoltages on transmission system components to levels within the equipment manufacturer's specified operating range. The studies also facilitate selection of surge protection devices that provide proper protection and have adequate power dissipation capacity.
Existing equipment capabilities and insulation coordination requirements determine acceptable transient and dynamic overvoltage limits.
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4. ADDITIONAL SYSTEM PERFORMANCE CRITERIA (continued)
4.4 Power Quality
The transmission system is designed to provide acceptable power quality. In addition to optimal adequacy and security of the power supply, the system is designed so that voltage fluctuations or total harmonic distortions of voltages are limited to the following levels:
4.4.1 Voltage Fluctuations
Voltage fluctuations or voltage flicker due to rapidly changing load is limited to a level, which will not exceed the company guidelines shown in Appendix E.
4.4.2 Harmonic Limits
The harmonic currents that an individual customer injects into the AP transmission system, as measured at the point of common coupling, shall not exceed the limits established by the company as shown in Appendix E.
4.4.3 Negative Sequence Currents
Negative sequence current studies are conducted so that damage to equipment resulting from negative sequence currents can be avoided. Unbalanced currents are caused by nonsymmetrical phase arrangements in transmission lines, unbalanced loads, or unequal transformer impedance. Negative sequence currents can produce excessive heating in the metallic wedges and retaining rings of turbine-generator rotors.
Due to the close proximity and strong influence of adjacent company interconnected EHV systems, negative sequence current studies for the EHV network are normally conducted on a multi-company basis. Negative sequence currents in generators should be limited to less than 5% of the positive sequence currents.
4.4.4 Negative Sequence Voltages
Negative sequence voltages should not exceed 22% of positive sequence voltages. A customer's load directly supplied from the transmission system should not cause more than 22% voltage unbalance.
4.4.5 Facility Outages
Lower levels of power quality can be tolerated when significant elements of the supporting transmission system are out of service.
24
5. LINE AND SUBSTATION CONFIGURATION CRITERIA
5.1 EHV
5.1.1 Lines
5.1.1.1 For reliability reasons, AP prefers to use only single circuit tower construction for 500 kV lines and will use single or double circuit construction on 345 kV as the need arises.
5.1.1.2 EHV lines should be routed on exclusive right-of-way in which any parallel lines
are of a lower voltage class, the exception being the approach to a substation.
5.1.1.3 Line crossings should be avoided and EHV lines should always occupy the highest position when crossing lower voltage lines.
5.1.2 Substations
5.1.2.1 The preferred bus configuration for EHV substations is "breaker and a half" when
more than four lines terminate on the bus. Most stations start out as ring buses and evolve to "breaker and a half" as terminal positions are added.
5.1.2.2 Transformer positions can be located on the buses, in the "string," or split between
the two.
5.1.2.3 Source lines and load lines should occupy alternate positions around a ring bus or be paired together on a "breaker and a half string."
5.1.2.4 Transformer loading is controlled as follows:
5.1.2.4.1 The second transformer is added when the first transformer loads
above its normal rating during single contingency events or the local areas supply experience line loading above their continuous rating when the transformer is removed.
5.1.2.4.2 Third and fourth transformers are added when the loss of one
transformer causes the remaining ones to load above their continuous rating.
5.2 Area
5.2.1 Line Configuration
5.2.1.1. Optimum Line Supply to Substations
When possible, a substation is supplied with two separate transmission lines with individual terminal facilities located within the substation.
25
5. LINE AND SUBSTATION CONFIGURATION CRITERIA (continued)
5.2 Area (continued)
5.2.1 Line Configuration (continued)
5.2.1.2 Double Circuit Lines
Consistent with sound engineering, economic and environmental considerations, double circuit transmission supply sources may be justified based on the unavailability of a suitable separate line supply as a second source. The length of a double circuit line is minimized for reliability reasons.
5.2.1.3 Radial Lines
Radial or a single transmission line supply to substations may be justified for an interim period when existing lower voltage lines can supply the substation load for the outage of the radial line.
When the substation load exceeds the capability of the lower voltage supply to provide backup for loss of the transmission supply, a second transmission supply is planned. Justification of a second line is based on reliability versus economic constraints with consideration given to the probability and timing of future area loads.
5.2.1.4 Multiple Rights-of-Way and Tower Lines
Whenever possible, it is preferable to have separate rights-of-way for critical supply lines in an area. In cases where it is necessary to have multiple circuits on the same right-of-way, the consequence of a structure failure or an outage that forces both circuits out of service must be weighed against the probability of such an event occurring and the cost and environmental impact of alternate routing configurations.
5.2.2 Substation Configuration
Substations are an integral part of the area transmission network and interface the transmission system with the subtransmission and distribution systems. Substations are developed in coordination with the area transmission system to meet thermal, voltage, and other reliability criteria.
5.2.2.1 Optimum Design
An area transmission substation is designed for two or more transmission line terminals, multiple bus sections, and at least four transformers to serve a minimum of 100 MVA load. The load may be served from local distribution circuits, the area subtransmission system, or a combination of both.
26
5. LINE AND SUBSTATION CONFIGURATION CRITERIA (continued)
5.2 Area (continued)
5.2.2 Substation Configuration (continued)
5.2.2.2 Line Terminals
Terminal switching facilities for the transmission lines are either automatic switches, circuit switchers, or circuit breakers as determined by system configuration and the ability of the protective relaying scheme to isolate a faulted line, bus section, or transformer.
5.2.2.3 Bus Sections
Bus sections are connected by automatic bus tie switches or circuit breakers as determined by system configuration and the ability of the protective relaying system to isolate a faulted line, bus section, or transformer. An effort is made to minimize the number of lines and transformers connected to each bus section.
5.2.2.4 Transformers and Sizing
Each transmission substation will have from four to six transformers when fully developed. The transformers will be protected on the high side by an automatic switch, circuit switcher, or breaker, and on the low side by a manual switch or breaker as required to isolate the faulted unit. Additional transformers are added as required for reliability and economic reasons.
Transformers supplying the subtransmission system are standard impedance triple-rated OA/FA/FA units. Depending on the location of the system, they may require automatic load-tap changing equipment.
Transformers serving distribution loads are triple-rated OA/FA/FA units with automatic load-tap changing equipment. Some units may require nonstandard impedance in order to limit fault current.
Approved by the Engineering Committee: November 30, 1993
APPENDIX A ECAR DOCUMENT NO. 1
RELIABILITY CRITERIA FOR EVALUATION AND SIMULATED TESTING OF THE ECAR BULK POWER
SUPPLY SYSTEMS Approved by the Coordination Review Committee September, 1967 Revised October, 1980
Revised May 27, 1998 Approved by the ECAR Executive Board October, 1967 Revised November 6, 1980
Revised July 27, 1998
(Included by reference.) Copies of this reference document can be viewed, printed or printed from the ECAR home page on the internet @ http:\\www.ecar.org.
North American Electric Reliability Council (NERC) PLANNING STANDARDS September 1997 (Included by reference.) Copies of this reference document can be viewed, printed or printed from the NERC home page on the internet @ http:\\www.nerc.com. Or can be obtained from the North American Electric Reliability Council (NERC) by request from the following address:
NERC 116-390 Village Boulevard
Princeton, New Jersey 08540-5731
Telephone: (609) 452-8060
Fax: (609) 452-9550
APPENDIX C
RELIABILITY COORDINATION PLAN
APS/PJM/VAPWR RELIABILITY COORDINATION PLAN
(RCP) REVISION 4
From APV Operations Analysis Group
On December 11, 1992
As Approved By The APS/PJM/VAPWR SYSTEM PERFORMANCE
STEERING COMMITTEE On
January 26, 1993
Effective February 1, 1993
Rev. 0 - 6/01/88 Rev. 1 - 8/17/88 Rev. 2 - 6/01/90 Rev. 3 - 11/01/90
A:\RCP\COVER.293 cdm:02/93
APS/PJM/VaPwr
RELIABILITY COORDINATION PLAN (RCP)
Rev. 0 6/88 Rev. 1 8/88 Rev. 2 5/90 Rev. 3 11/90 Rev. 4 12/92
1.0 PURPOSE
The RCP outlines steps to be taken to avoid or remedy unreliable operation on the interregional bulk power transmission system. 2.0 GENERAL
2.1 THERMAL OPERATION - The APS/PJM/VaPwr bulk power transmission system shall be operated so that no bulk power transmission facilities exceed their normal rating on an actual basis and so that no facility will exceed its emergency rating (as determined by the "control area" owning the facility) following the sudden loss of any single generation or transmission facility.
2.2 VOLTAGE/REACTIVE OPERATION - The APS/PJM/VaPwr bulk power transmission system shall be operated so that the actual and post-contingency voltage/reactive requirements of the control area owning the facility are not violated.
2.3 NOTIFICATION - It is the intent of this plan that the initiating control area will notify all other participants of implementation or cancellation of any level of this plan. The participants are defined as AEP, APS, CEI, DL, OE, PJM, and VaPwr. In addition, the ORNS teletype should be used to notify ORNS members of the implementation or cancellation of Levels II and IV. It is the responsibility of each control area to notify their appropriate operating company personnel.
2.4 APS, PJM, and VaPwr Operation Planning groups shall regularly examine system conditions and provide the system operators with procedures and methods to assure that the system will be operated reliably.
2.5 APS, PJM, and VaPwr System Operations shall communicate the current and expected reliability status of their system to all neighboring systems.
2.6 APS, PJM, and VaPwr System Operators shall react as requested when a reliability violation is declared by another system. However, a control area may notify the requesting control area that it is unable to comply if the requested action will cause a reliability violation on its own system. The requesting control area should supply as much information as is readily available about the system conditions. Disputes and any in-depth analysis questions should be resolved after actions have been taken and the system has returned to a reliable state.
3.0 APS/PJM/VaPwr TRANSMISSION LIMITS
The operation of APS, PJM, and VaPwr can be affected by internal or external transmission limits. These limits can be of a thermal nature (actual or post-contingency overloads), of a reactive nature (actual or post-contingency voltage criteria violations), or of a steady-state stability nature (large system angular differences).
The system owning the limiting facility is responsible for detecting the problem, determining the indicator of the limit and initiating the levels of this plan required to assure reliable operation. When possible, limiting conditions should be anticipated in advance of each operating season and reviewed for appropriateness by all participants of this agreement. Identification of anticipated limits and preliminary corrective strategies should be included as a part of this document.
4.0 SUDDEN SYSTEM CHANGES
Sudden voltage and MW flow changes can be an indication that transmission switching or sudden generation loss may have occurred on the bulk power system. Loss of generation or transmission facilities can affect the reliable operation of the interconnected system. Information on actual switching occurrences or generation loss (scheduled or unscheduled) should be exchanged with interconnected systems as soon as possible after the occurrence. The impact of these changes on the reliable condition of the interconnected system should be considered in reliability evaluations.
If a transmission line tripped and did not automatically reclose, the transmission system should be analyzed and operated assuming that the facility is "locked out." Appropriate system adjustments should be made to protect for the next contingency.
Recognition should be given to the expectation that a generation loss will be compensated for by generation increases on the bulk power system. Curtailments should be delayed for ten minutes to allow internal generation to compensate for a reported unit loss. 5.0 DEFINITIONS:
The method for controlling to a limit, when external assistance is required, shall be a four level plan. The following is a definition of each level of the Reliability Coordination Plan.
LEVEL I (Controlled Loading Level) - is the point determined by the initiating control area where the increase in transfers should be controlled in anticipation of a deteriorating reactive or thermal situation.
LEVEL II (Small Block Curtailments) - is the point determined by the initiating control area to result in marginally acceptable post-contingency operation, while anticipating increased transmission loading. Transfers are frozen or may be curtailed up to 500 MW per pass in anticipation of a deteriorating reactive or thermal situation.
LEVEL III (Large Block Curtailments) - is the point determined by the initiating control area to result in the minimum acceptable post-contingency operation. Curtailments may be up to 1000 MW per pass. LEVEL IV (Emergency Operations) - is the point where probable voltage collapse or cascading thermal overloads will result if critical single contingency should occur. Participating control area must reduce their imports within a reasonable time (20 min.) using all available means including emergency procedures such as voltage reduction, interruptible curtailments, starting of combustion turbines, and load shed. Upon notification of load shed by an importing utility (PJM, VaPwr), APS will also shed load to maintain system reliability. Level IV-A should only be experienced after the occurrence of a less critical contingency or when curtailments were not of sufficient magnitude in previous levels. LEVEL IV-B (Emergency Load Shed) - is the point that analysis has shown may result in imminent voltage collapse or cascading thermal overload. A critical contingency has occurred and load shedding by APS, PJM, and VaPwr should be initiated immediately to avoid a collapse. 6.0 TRANSFER CURTAILMENT PROCEDURE The following procedure applies the general principles stated above to the specific case of west-to-east transfers that cause a limiting condition within the APS system or an importing system (PJM and VaPwr). The participants have agreed that each shall observe an appropriate Curtailment Reference Value (CRV) for this procedure, taking into account existing obligations (among the participants and between the participants and others)
to maintain reliable and, to the extent consistent therewith, economical operations. Until superseded by revision of this RCP, the agreed Curtailment Reference Value for each participant is:
PJM = 2245 MW Rev. 4 APS-VAPWR = 300 MW 12/11/92 VAPWR = 1300 MW
Prior to implementation of any step of this plan, the control area initiating the plan shall verify that all actions or coordination that do not involve an economic penalty have been utilized to mitigate this condition. This includes the use of "Heavy" Reactive Support under the Voltage Coordination Plan (VCP).
6.1 LEVEL I - (CONTROLLED LOADING LEVEL) When the stated Level I is reached, the initiating control area shall notify all participants in the agreement that no additional transfers be loaded or scheduled that would increase loading on the limiting facilities, without prior consent by the initiating control area. The control is to be exercised in such a manner as to not exceed Level I and/or not anticipated to cause large cuts in Level II. The initiating control area shall request a listing of net western transactions in effect at this time. The net western total includes transactions from or through ECAR to PJM and VaPwr. The initiating control area shall contact all participants when Level I is declared and whenever transactions are adjusted within Level I. The initiating control area shall maintain a log of these transactions and identify actions requested and performed as a result of initiating this plan. NOTE: If a control area is near Level I when a large block of transfers is scheduled to ramp in, the affected control
area may request that the transfers be picked-up in smaller increments to avoid overshooting Levels I and II which would result in the need for immediate curtailments.
OPERATION AT THIS LEVEL IS ACCEPTABLE
Restoration - As conditions permit, purchase restorations shall be permitted in Level I. All cuts from Level II and III actions are restored in Level I. If curtailments took imports below CRV for one or both control areas, one control can restore up to the same percent of CRV as the other control area before sharing the restoration in the ratio of the curtailments. After all cuts are restored, notify ORNS that we are no longer requesting a restriction of transfers.
Increases - After all cuts have been restored and as conditions permit, purchases that are to be
increased are in the ratio as defined for the current contingency limit and transfer level. Purchases to increase a participant's imports up to its CRV will be permitted prior to the increase of purchases that would exceed a participant's CRV. If both control areas are held below their CRV, the one with the lowest percent of CRV loaded may first increase its purchases up to the same percent of CRV as the other. The two control areas would then be allowed to increase purchases in the curtailment ratio as defined for the current contingency limit.
NOTE: The initiating control area is responsible for contacting each importing area each time an increment of
transfers can be safely added to the schedules. No controlled transfers may be restored or added without the consent of the declaring area. Level I is ended after all desired schedules have been loaded and critical facility loading are stabilized below the current Level I trigger point.
6.2 LEVEL II - (SMALL BLOCK CURTAILMENTS) When the stated Level II is reached, the initiating control area shall notify all participants and the ORNS members to request the following actions in the sequence shown below.
1. Request that no additional transfers be loaded that would increase flows on the critical facilities (freeze transfers).
2. Request control areas to shift generation internally to alleviate contingency problem. If no action
possible, proceed to #3.
3. Request control areas to reduce purchases from west up to 500 MW. If both control areas have purchases greater than their Curtailment Reference Values, curtailments will be shared in the ratio in effect for the anticipated contingency. If only one control area has purchases greater than its Curtailment Reference Value, it must reduce those purchases by up to 500 MW or to its Curtailment Reference Value.
Purchases from the west above the Curtailment Reference Values must be curtailed by all areas prior to curtailment of any purchases below the Curtailment Reference Value for any area.
If no action possible or additional action is needed, go to #4.
4. Request control areas to curtail purchases below their CRV. If both control areas are not loaded up to
their CRV, only the control area with the highest percent CRV loading curtails until both areas are at equal percent of CRV. They then curtail together based on the curtailment ratio in effect for the anticipated contingency. Contracts to be curtailed are the choice of the purchasing control area. If a control area cannot comply because the imports are needed to serve customer load, it should make every attempt to purchase from or through another control area including the remaining plan participant. Care should be taken so that the replacement purchase does not aggravate the current problem. If the control area cannot purchase power from any other control area, the remaining control area in the plan should take the full curtailment unless the imports are needed to serve customer load.
The goal of Level II actions is to prevent critical facility loading from reaching Level III. Level II actions 3 and/or 4 may be repeated as necessary to accomplish this goal. At the time of any actions in Level II, the initiating control area should record western purchases and all actions taken. Curtailments for each pass through Level II are not expected to exceed 500 MW.
OPERATION AT THIS LEVEL IS ACCEPTABLE
Readjustment - Continue to review conditions. If conditions initially prevented a control area from full
compliance of Level II curtailments, move toward redistribution of curtailments to the intended ratios as conditions permit.
Restoration - Level II is ended whenever critical facility loading have dropped and stabilized below
the current Level II trigger point. All participants should be notified when Level II is canceled. ORNS is not notified until all cuts have been restored in Level I. Restoration of any curtailments or adding of any previously frozen transfers will take place in Level I.
NOTE: If Level I was not implemented prior to Level II, then the initiating control area shall execute Level I actions
in conjunction with Level II.
6.3 LEVEL III - (LARGE BLOCK CURTAILMENTS)
When the stated Level III is reached, the initiating control area shall notify all participants and request large block (up to 1000 MW) transfer curtailments. The initiating control area shall request immediate curtailments of up to 1000 MW allocated to each control area in the curtailment ratio for the contingency associated with implementation of Level III. If both control areas have purchases greater than their Curtailment Reference Values curtailments will be shared in the ratio in effect for the anticipated contingency. If only one control area has purchases greater than their Curtailment Reference Value, it must reduce those purchases by up to 1000 MW or to their Curtailment Reference Value.
Purchases from the west above the Curtailment Reference Value must be curtailed by all areas prior to any curtailment of any purchases below the Curtailment Reference Value for any area.
Each control area requested to curtail should make every effort to comply immediately. This includes making an effort to purchase replacement power from other utilities provided that such purchases do not aggravate the situation.
The goal of Level III actions is to return the critical facilities to or below Level II and remain out of Level III. Repeat curtailments as necessary to achieve this goal. Curtailments for each pass through Level III are not expected to exceed 1000 MW.
If a control area cannot comply because the imports are needed to serve customer load, it should make every attempt to purchase from or through another control area including the remaining plan participant. Care should be taken so that the replacement purchase does not aggravate the current problem. If the control area cannot purchase power from any other control area, the remaining control area in the plan should take the full curtailment if it does not jeopardize serving its load.
OPERATION AT THIS LEVEL IS UNDESIRABLE
Readjustment - If Levels I and II were not implemented prior to Level III, it is permissible to allow control areas to readjust curtailments to reflect their curtailment ratio and/or their preferred operating configuration. This is to be done after situation has stabilized and could involve generation shifts and changes in purchases.
Restoration - Level III is ended whenever critical facility loading have dropped and stabilized below
the current Level III trigger point. Restoration of any curtailments or adding any previously frozen transfers will take place in Level I.
6.4 LEVEL IV - (EMERGENCY CONDITIONS)
LEVEL IV-A (EMERGENCY OPERATIONS) - The actual conditions have reached a point where a critical single contingency would cause probable voltage collapse or cascading thermal overloads. That is, the control area is operating in the area beyond Level III on a pre-contingency basis. At this time, all participating control areas MUST reduce their imports by their share of 1000 MW within a reasonable time period (=20 min.). Curtailment shares are based on the curtailment ratio defined for the critical contingency encountered and without regard to the CRV. The control areas must use all available means including all applicable Emergency Procedures such as voltage reduction, interruptible curtailments, starting combustion turbines, emergency transfers, and load shed. All participants and ORNS shall be notified of Level IV-A and any requested actions.
Upon notification of load shed by an importing utility (PJM or VaPwr), AP will shed load to maintain system reliability.
Level IV-A should only be experienced after the occurrence of a less critical contingency or when curtailments of imports were not of sufficient magnitude in previous levels. The goal of Level IV-A is to restore to Level III conditions or better.
OPERATION AT THIS LEVEL IS UNACCEPTABLE
Readjustment - After system conditions have stabilized at Level III or better, adjustments to purchases can be made so long as the total import from ECAR does not increase. These adjustments should result in purchase levels that would have resulted if curtailments had been made recognizing each control area's CRV and applicable curtailment ratio.
Restoration - As soon as conditions permit, system loads shall be restored in the same proportion as
the load shed. Purchases necessary to restore load and end emergency procedures may be restored while in Level III.
Additional purchases beyond those needed to restore load and end emergency procedures should not be restored until Level I or better conditions are achieved. Purchases should then be restored as specified under restoration in Level I.
Notify all plan participants and ORNS when Level IV is canceled.
LEVEL IV-B (EMERGENCY LOAD SHED) - a critical contingency has occurred and conditions in the
initiating control area have reached the minimum survivable operating point.
The initiating control area shall request APS, PJM, and VaPwr to shed load immediately and in an equal amount specified on the limit sheet.
Coincident with load shedding, all remaining transactions that are judged to adversely affect the problem should be brought to zero. Emergency purchases that could be beneficial in alleviating the condition or could be used to restore load without adverse effect should be made coincident with other actions in Level IV. All participants and ORNS should be notified of these actions as soon as possible. The goal of Level IV-B is to restore the system to Level III conditions. OPERATION AT THIS LEVEL IS UNACCEPTABLE
All actions are judged necessary to avert a system collapse.
Readjustment - After system conditions have stabilized at Level III or better, adjustments to purchases can be made so long as the total import from ECAR does not increase. These adjustments should result in purchase levels that would have resulted if curtailments had been made recognizing each control area's CRV and applicable curtailment ratio.
Restoration - As soon as conditions permit, system loads shall be restored in the same proportion as
the load shed. Purchases necessary to restore load and end emergency procedures may be restored while in Level III.
Additional purchases beyond those needed to restore load and end emergency procedures should not be restored until Level I or better conditions are achieved. Purchases should then be restored as specified under restoration in Level I.
Notify all plan participants and ORNS when Level IV is canceled.
Rev. 1 - 8/88 - CRV language added Rev. 2 - 5/90 - Redefine Level I and II actions. Other minor changes as noted above. Rev. 3 - 11/90 - Redefine curtailment methods for CRV. Rev. 4 - 12/92 - Rename the ODEC CRV as APS-VaPwr.
FILE:A:RCPREV4.WR1:cdm Rev.4, 12/14/92
North American Electric Reliability Council Transmission Transfer Capability A Reference Document for Calculating and Reporting the Electric Power Transfer Capability of Interconnected Electric Systems May 1995 (Included by reference.) Copies of this reference document can be viewed, printed or printed from the NERC home page on the internet @ http:\\www.nerc.com. Or can be obtained from the North American Electric Reliability Council (NERC) by request from the following address:
NERC 116-390 Village Boulevard
Princeton, New Jersey 08540-5731
Telephone: (609) 452-8060
Fax: (609) 452-9550
APPENDIX E VOLTAGE FLICKER AND HARMONIC DISTORTION LIMITS VOLTAGE FLICKER The voltage fluctuations (flicker) a customer's load causes at the point of common coupling shall remain below the Voltage Flicker Limits of Figure #1. APS uses UHP International, Inc. Network Flicker/Harmonic Analyzer, using the RMS unweighted scale, to determine compliance with this limit.
FIGURE #1
HARMONIC DISTORTION LIMITS General Two criteria are used to determine harmonic distortion. The first is the limitation on the harmonic current that a user can transmit into the utility system. The second is to limit the amount of voltage distortion at the metering point of any customer. The following tables are provided as limits for these amounts and are for continuous, steady state operations of ten minutes or more. For transients of one minute to ten minutes, the values can be increased to 1.25 times the levels in the table and for less than one minute, to 1.50 times the levels. Current Distortion The following tables list the harmonic current limits based on the load current with respect to the short circuit strength of the power system to which it is connected. The tables list the maximum amount of harmonic current distortion from non-linear loads, in percent with respect to the 60 Hz current at the meter location. T A B L E 1 Maximum Harmonic Current Distortion Levels (in % IL) For Each Individual Odd Harmonic (NOTE 1) Where Service Voltage is Less Than 69 kV
ISC/IL
DC Note 3
<11
11#H<17
17#H<23
23#H<35
35#H
THD
#20
(NOTE 2)
0
4.0
2.0
1.5
0.6
0.3
5.0
>20 & #50
0
7.0
3.5
2.5
1.0
0.5
8.0
>50 & #100
0
10.0
4.5
4.0
1.5
0.7
12.0
>100Ϩ
0
12.0
5.5
5.0
2.0
1.0
15.0
>1000
0
15.0
7.0
6.0
2.5
1.4
20.0
T A B L E 2 Maximum Harmonic Current Distortion (in %IL) For Each Individual Odd Harmonic (NOTE 1) Where Service Voltage is ∃69 kV But #138 kV
ISC/IL
DC Note 3
<11
11#H<17
17#H<23
23#H<35
35#H
THD
#20
(NOTE 2)
0
2.0
1.0
0.75
0.3
0.15
2.5
>20 & #50
0
3.5
1.75
1.25
0.5
0.25
4.0
>50 & #100
0
5.0
2.25
2.0
0.75
0.35
6.0
>100Ϩ
0
6.0
2.75
2.5
1.0
0.50
7.5
>1000
0
7.5
3.5
3.0
1.25
0.7
10.0
T A B L E 3 (NOTE 4) Maximum Harmonic Current Distortion Levels (In % IL) For Each Individual Odd Harmonic (NOTE 1) Where Service Voltage is Greater Than 138 kV
ISC/IL
DC Note 3
<11
11#H<17
17#H<23
23#H<35
35#H
THD
#50
0
2.0
1.0
0.75
0.3
0.15
2.5
>50
0
3.0
1.5
1.15
0.45
0.22
3.75
Where:
H = Order of Harmonic (Multiple of Fundamental)
THD = Total Harmonic Distortion in Percent where:
ISC = Maximum 60 Hz RMS short circuit current at the metering point.
IL = 60 Hz (Fundamental Frequency) RMS load current at the meter location during the time of harmonic analysis. For new connections, IL is calculated from the size of the transformer to be installed.
IH = RMS Magnitude of the harmonic current at frequencies above the fundamental.
And:
The values of THD and %IH as calculated above should be less than or equal to those listed in Tables 1-3.
NOTES: 1. Even harmonic limits are 25% of odd harmonic values. 2. All power generation equipment is limited to these values regardless of ISC/IL. 3. Current distortions that result in DC offset are not allowed. 4. Data applies to power generation equipment in addition to load equipment. Voltage Distortion For limitations on the amount of voltage distortion, which may result at the customer's meter location, the following table will apply:
100*I
)I...++I+I+I( = THDL
1/2h
23
22
2dc
2
x100II=I%
L
HH
T A B L E 4 Maximum Harmonic Voltage Distortion (in % V1) at the Customer's Meter Location
< 69 kV
∃69 to #138 kV
>138 kV
Maximum for Individual Odd and Even Harmonics
3.0
1.5
1.0
THD
5.0
2.5
1.5
Where:
THD = Total Harmonic Distortion in Percent where:
VH = Magnitude of each harmonic voltage at frequencies above the fundamental (RMS)
V1 = 60 Hz RMS Voltage
And:
Both V1 and VH have to be checked phase-to-phase and phase-to-ground.
The values of THD and %VH as calculated above should be less than or equal to those listed in Table 4.
100*V
)V...++V+V+V( = THD1
1/2h
23
22
2dc
2
x100VV=V%
1
HH
Commutation Notches Commutation action, which is a transient short circuit resulting from thyristor's switching from one phase to the next is a source of harmonic current and voltage distortion. The voltage distortion is more important, because many thyristor packages use the voltage (assumed sinusoidal) zero crossing for control, and will thus be limited at the user's meter location as follows: 1. Depth of the commutation notch should not exceed 20% of the peak voltage magnitude. 2. The area of the commutation notch, which is equal to the width of the notch in microseconds times the
average depth of the notch in volts, should not exceed 22,800 for a 480 volt service. For other service voltages, this limit will be multiplied by VLL/480.
3. As in Table 4, the total harmonic distortion of the voltage at the service panel shall not exceed 5%.
APPENDIX B- Information Provided by Developer
