Reliability Criteria For System Planning - OATI webOasis · Web viewThe reliability criteria define the performance requirements for planning the IPCo system. The performance requirements

IDAHO POWER COMPANYFERC FORM No. 715

PART IVRELIABILITY CRITERIA

Enclosed Idaho Power Company’s internal reliability criteria The Idaho Power Company internal criteria plus the NERC/WECC

criteria and other documents submitted by the WECC constitute Idaho Power Company’s complete response to FERC for Part IV.

Contact Person: Becky StewartMailing Address: P.O. Box 70

Boise, Idaho 83707-0070E-mail [email protected] Number: 208-388-2284Facsimile Number: 208-388-6647

RELIABILITY CRITERIAFOR

SYSTEM PLANNING

IDAHO POWER COMPANY

SYSTEM PLANNING DEPARTMENT

Revised February 2009

FERC Form No. 715 2010 FilingPart IV: Reliability Criteria

Table of Contents

I. Introduction............................................................................................................1

Philosophy...................................................................................................1Description...................................................................................................1

II. Definitions............................................................................................................1

The Transmission System...................................................................................................1Remedial Actions...................................................................................................2Loads...................................................................................................2Other Definitions...................................................................................................3

III. Assumptions............................................................................................................3

Generation...................................................................................................3Equipment Ratings...................................................................................................4Upgrade of Transmission Service...................................................................................................4

IV. System Performance Requirements............................................................................................................4

Steady-State Voltage Requirements...................................................................................................4Reactive Switching...................................................................................................4Post Disturbance Requirements...................................................................................................5Transient Stability...................................................................................................5Performance Levels...................................................................................................6Disturbance-Performance Tables...................................................................................................6Disturbance-Performance Table...................................................................................................8Performance Levels Table...................................................................................................8

V. Bridger System Performance Requirements............................................................................................................9

Pre-Transient (Steady State) Period...................................................................................................9Transient Period...................................................................................................9Post-Transient Period...................................................................................................10

2


Idaho Power CompanyReliability Criteria for System Planning

I. Introduction

Philosophy

The Idaho Power Company (IPCo) transmission system is planned to provide cost-effective and reliable service. The system will have sufficient strength or capacity to maintain continuity and quality of service to electrical loads during common contingencies or system disturbances. For certain uncommon contingencies, it is not reasonable to provide enough capacity to maintain full service, so a reduction in quality of service or even interruption of service is allowed.

Description

The reliability criteria define the performance requirements for planning the IPCo system. The performance requirements are given in terms of the effects that are allowed on electrical loads and the transmission system as a result of various contingencies. The criteria are deterministic, that is, the same generalized performance is specified for specific types of contingencies and applied uniformly over the system. Application of the criteria is expected to provide overall system cost-effectiveness.

The performance criteria for the Jim Bridger system is slightly different than the criteria for the rest of the system. The Bridger performance criteria is outlined in Section V.

Criteria adopted by the Western Electricity Coordinating Council (WECC), "Reliability Criteria for Transmission System Planning," limit the effects that disturbances in one system can have on other systems. The IPCo system is planned to satisfy both the IPCo and WECC criteria.

II. Definitions

The Transmission System

Main Grid Transmission Service: The transmission lines and related substations that carry bulk power. The main grid provides the primary connections among major load areas, large generating plants, major interties, and some intermediate load areas. The main grid includes all 500 kV, 345 kV, 230 kV, and those lower voltage lines that perform the main grid function. Those portions of substations, including transformers, supporting the main grid lines are also included. Examples of these are the Bridger-Goshen 345 kV, Kinport-Midpoint 345 kV, Boise Bench-Caldwell 230 kV, and Boise Bench-Locust 230 kV lines.


Improved Radial Service: Any substation on a transmission loop, and the lines in the loop, where one of the sides of the loop serving the improved radial substation can better serve normal peak load than the other. Examples include the McCall 138/69 kV loop, the Wood River 138 kV loop, and many of the 46 kV loops in the Southern and Eastern Division.

Radial Service: A substation and the transmission line that provides the only connection between the substation and the rest of the transmission system. All substations along the radial line are included.

Remedial Actions

Remedial action schemes, also known as special protection systems or special stability controls, are planned protective measures which are initiated following a transmission system disturbance to provide for acceptable system performance.

Remedial actions, the individual protective measures that make up a remedial action scheme, are automatic non-continuous supplementary controls that perform functions other than the isolation of electrical faults. Examples of remedial actions that may be used on the IPCo system are:

Generator Dropping and/or Ramping: Disconnection or reduction in power output of certain selected generators to prevent system breakup.

Load Tripping: Disconnection of certain selected loads to prevent system breakup or voltage collapse.

Load Shedding: Reduction of load by means of underfrequency or undervoltage relays to prevent disconnection of frequency sensitive generators, minimize frequency decline, as well as prevent voltage collapse. The amount of load shedding is optimized such that a minimum amount of load is shed in order to maintain voltage or frequency criteria.

Reactive Switching: Application or removal of shunt or series capacitors, or shunt reactors, to prevent system breakup or voltage collapse.

Islanding: Disconnection of a portion of the system from the rest of the interconnected grid to prevent widespread cascading outages.

Loads

Extreme Peak Load: The seasonal peak load expected for weather conditions that have a 10% probability of occurrence.

90% Load: The load level that is exceeded less than 10% of the time on a load duration curve based on normal peak load.

Normal Light Load: The yearly minimum load expected under normal system and weather conditions.

2

FERC Form No. 715 2010 FilingPart IV: Reliability CriteriaOther Definitions

Cascading: The uncontrolled successive loss of system elements in which the loss of each successive element is contingent upon prior loss of elements. Loss of firm or non-firm load is not considered cascading.

Delayed Clearing: Delayed clearing occurs when the primary protection fails to clear the fault and backup relaying is required.

III. Assumptions

To assist in the planning process for facility additions, the following assumptions are made:

Generation

Main Grid GenerationProduction levels of main grid Idaho Power generation (Hells Canyon, Bridger, Upper Snake), other utility, and non-utility generation in the Idaho area will be set at normal seasonal levels or as necessary to meet specific objectives of the study.

Non-Main Grid GenerationProduction levels of Idaho Power or non-utility generation embedded in IPCo’s subtransmission or distribution system will be set at a value to be expected 80% of the time for the season under study or as needed to meet the objectives of the study.

External GenerationProduction levels of external generation outside of the Idaho area will be set as necessary to meet the objectives of the study.

VariationsBoth high and low hydro generation patterns may be evaluated to test the system under conditions of maximum regional export and import schedules. Other plausible variations in generation patterns that produce stresses in the transmission system may also be examined.

Typically, the effects of heavy east and west power flows through the IPCo system are studied.

Equipment Ratings

Lines, transformers, generators, switch gear, terminal equipment, etc. will be loaded so as not to exceed applicable continuous or emergency limits established by IPCo.

For long range planning studies, nameplate equipment ratings are typically used for normal thermal rating. Short-term emergency ratings are typically 110% of nameplate during the summer and 120% of nameplate during the winter. The short-term ratings infer that equipment loading can be reduced to the normal thermal rating within an hour.

3

FERC Form No. 715 2010 FilingPart IV: Reliability CriteriaFor near term planning, actual equipment ratings may be determined by performing detailed studies on the equipment and the involved system.

Upgrade of Transmission Service

The decision to upgrade radial service to improved radial or improved radial to main grid transmission service must be evaluated on a case-by-case basis and is dependent on economics and risk. Specifically, some items that should be addressed are:

Upgrade costs

Risk

- Willingness to subject customers to load shedding

- Probability of an occurrence

- Customer loss of load value.

IV. System Performance Requirements

Steady-State Voltage Requirements

The intent of this requirement is to ensure adequate transmission voltage in order to maintain distribution voltages. Per ANSI specifications, the utility is to provide at the customer's service entrance a voltage of 1.0 per unit, plus or minus 5% under normal operating conditions and plus 5.83% or minus 8.33% under emergency conditions. This equates to a normal operating voltage range of 126 V to 114 V and an emergency range of 127 V to 110 V on a 120 V base.

Generally, for normal operating conditions, transmission voltages are maintained within plus or minus 5%. The 500 kV voltages range between 500 and 550 kV.

Reactive Switching

Voltage swings caused by any single step of shunt capacitor or reactor switching should generally not exceed 3% on any load bus with all lines in service. Such swings should not exceed 5% with any line or transformer out of service or where sufficiently small size capacitor blocks are not available in standard groups. If acceptable to the customer, swings of up to 7% may be allowed on an individual customer’s bus where high costs make it uneconomical to improve performance. The sensitivity of the customer’s load to changes in voltage as well as the frequency of occurrence are other factors to be considered when determining maximum allowable voltage swing.

Capacitors or reactors should be added to hold voltage schedules if schedules cannot otherwise be held on the actual system for normal peak or light load conditions with all lines in service. Switching capacitor banks or reactors, with all lines in service, should generally not cause voltage to be outside of the normal operating range.

4

FERC Form No. 715 2010 FilingPart IV: Reliability CriteriaTo meet the steady-state voltage requirements, all regulating equipment, including generators, must be operated within limits. An allowance, developed from operating records (generators, capacitors, or reactors) should be made for that equipment which is unavailable because of scheduled or forced outages.

With normal light loads and low transfer conditions or under other conditions that produce minimum system loading, it shall be permissible to remove a 230 kV or higher line or lines from service to keep voltages from exceeding maximum levels. This practice should be used as a last resort; after all available reactive devices have been switched. The reduced system must still satisfy all other performance requirements of Section IV and shall not compromise service reliability.

Post Disturbance Requirements

For all credible outages, voltage stability of the system must be maintained and sufficient voltage and reactive margin must be provided to ensure that voltage collapse will not occur.

For single contingencies (N-1), the post-disturbance operating point for the critical main grid transmission busses must maintain a 250 MVAR reactive margin from the point of voltage instability (nose of the Q-V curve) with successful operation of the remedial action schemes. And, for double contingencies (N-2), 200 MVAR of reactive margin will be maintained at the critical main grid transmission busses.

If facilities are overloaded beyond their short term emergency ratings following an outage, the system will be readjusted such that facilities are within their short term emergency ratings within 10 minutes. Facility loadings will be further reduced to their continuous levels within 30 minutes of the overloading event. Typically overloads are reduced by:

Insertion/bypassing of series capacitors and/or reactors. Opening/closing transmission lines and/or transformers. Adjusting phase shifters (when available) Re-dispatching generation (if acceptable) Load dropping (if acceptable)

Transient Stability

Remedial Actions Remedial actions other than those involving firm load dropping may be used for any contingencies to maintain stability. Remedial actions involving load tripping or shedding may be used if the requirements for serving load, as specified in the Disturbance-Performance Tables, are met.

5


Faults Stability must be maintained for a permanent three-phase fault with normal clearing time or a single-phase fault with delayed clearing. For disturbances specifying a non-three-phase fault, a double line-to-ground (LLG) fault with normal clearing will be used. Faults should be applied at the line terminals of the power circuit breaker.

Clearing times should be the sum of guaranteed maximum relay and breaker times for the fault location being studied.

Load Representation :IPCo summer or winter load representation should generally be used.

Generation :Generation should be represented as operated, with governor droop or blocking as appropriate. The Power System Stabilizer (PSS) should be assumed in service per WECC guidelines or as otherwise operated.

Damping :Acceptable system performance requires positive damping of all appropriate machine quantities, bus voltage, frequency, and tie line power.

Performance Levels

The performance levels for interconnected bulk power systems logically range between a level having no appreciable adverse system effects and a level where all allowable actions have been taken and load shedding and islanding may take place. The letters A, B, C, and D were selected to represent this range of performance.

The A, B, C, and D performance levels are defined in terms of conditions and remedial actions that may be required on systems other than the one in which the disturbance originated. These levels are consistent with performance levels defined in the WECC criteria. The electrical performance requirements for each level are specified in the disturbance-performance tables.

Level A is system normal with all facilities in-service and all bus voltages, transmission lines and transformers flows within nominal limits and ratings.

Level B is used to specify performance for single contingencies. No loss of load should occur and performance should be sufficient to provide good quality of service. WECC requires that no significant adverse effects occur outside of the IPCo system.

Level C specifies performance for multi-element outages. Firm and interruptible load shedding may occur for this performance level; however, facility loadings are to remain within emergency limits. Performance should be sufficient to avoid damage to customer equipment and no cascading or instability is permitted. The WECC criteria allow substantial adverse effects to occur outside of the IPCo system.

6


Disturbances within the Level C performance level have a wide range of probability of occurrence. For instance, the loss of a bus section is more probable than the loss of two system elements. Facility upgrades are dependent upon risk and if a particular outage occurs more often than expected, its performance level requirement may be changed.

Level D Extreme event resulting in two or more (multiple) elements removed or cascading out of service. May involve substantial loss of load/generation in a widespread area or areas. Portion or all of the interconnected system may or may not achieve a new, stable operating point. These are risk assessment type studies run to evaluate the performance of the system under unforeseen events. They are normally studied in evaluating effectiveness of safety net schemes.

Disturbance-Performance Tables

The Disturbance-Performance Tables specify the transmission system performance required for contingencies that are considered credible events that merit consideration in planning the IPCo system. Performance levels are given for the main grid, improved radial service, and radial service. The accompanying Performance Levels Table specifies the requirements to be met for each performance level.

The following rules are to be observed when applying the tables:

Pre-contingency (System Normal), all bus voltages, transmission lines and transformers flows within nominal limits and ratings.

Contingencies are credible disturbances that result in automatic disconnection (momentary or permanent) or emergency manual disconnection of a transmission facility or generator. This table does not address non-credible contingencies.

The contingencies listed in the table provide a basis for estimating a performance level to which a disturbance not listed in this table would apply.

During outages, it is permissible to sectionalize the system, reconnect loads, or adjust generation to control overloads on transformers or lines. Minimum voltage requirements apply after system adjustments are made.

All multiple contingencies are considered to be independent events except for lines in the same corridor, pass, or right-of-way or that connect to a common bus or breaker. Independent contingencies are considered to be non-simultaneous, and 1/2 hour should be assumed to be available between contingencies for system adjustments. Dependent contingencies should be considered to occur simultaneously.

System transient and voltage stability must be maintained for all performance levels.

Positive system damping is required for all performance levels A thru C.

7


The criteria does not permit cascading or subsequent blackout of islanded areas other than possibly non-credible extreme events studied under category D.

8


Disturbance-Performance Table

SYSTEM CONTINGENCY (ELEMENTS LOST)PERFORMANCE

LEVEL REQUIRED

Main Grid None (System Normal) A

Transmission One Generator B

Service One Circuit

One Transformer

Bus Section C

Two Generators

Two Circuits

Three or more Circuits on ROW D

Entire Substation

Entire Generation Plant including Switchyard

Improved Radial None (System Normal) A

Service Weaker Line C

Stronger Line D

Radial Service None (System Normal) A

The Radial Line All Load Curtailed

Performance Levels TableREQUIREMENTS PERFORMANCE LEVELLoads A B C D

Serve Extreme Peak Load X X

Serve 90% Load X

Serve Load to Best Ability X

Equipment Ratings

Loadings Within Thermal Limits (System Normal) X

Loadings Within Emergency Limits X X X

Steady State Voltages (after system adjustments)

Maintain Distribution Bus Voltages Within Normal Range (System Normal) X X

Maintain Distribution Bus Voltages Within Emergency Range X

Post Outage Voltage Deviation of 5% for All System Buses* X

Post Outage Voltage Deviation of 10% for All System Buses X

Transient Voltages

9


Max Voltage Dip of 25%; Max Duration of Voltage Dip > 20% = 20 Cycles X

Max Voltage Dip of 30%; Max Duration of Voltage Dip > 20% = 40 Cycles X

Max Voltage Dip of 30%; Max Duration of Voltage Dip > 20% = 60 Cycles

Transient Frequencies

Minimum Frequency of 59.6 Hz X

Minimum Frequency of 59.0 Hz X

Minimum Frequency of 58.1 Hz

* Discretionary – Greater than 5% post-outage voltage deviation is acceptable if minimum voltage remains above nominal of 0.950 per unit.

V. Bridger System Performance Requirements

The Bridger system performance criteria was jointly developed by Idaho Power and PacifiCorp.

Pre-Transient (Steady State) Period

Bus voltages within the PP&L, UP&L & IPCo systems will be kept within 0.95 and 1.05 per unit.

Equipment loadings will be kept within allowable continuous ratings.

Synchronous condensers at Kinport, Goshen and Brady will be operated at the middle of their boost-buck range (same amount of dynamic range available in both directions).

At high transfer levels, the Jim Bridger 345 kV 200 MVAR shunt capacitor bank should be in-service with Jim Bridger 345 kV voltage at 1.05 per unit.

Transient Period

WECC Reliability Criteria For Transmission System Planning.

Post-Transient Period

For single contingency (N-1), the post-disturbance operating point for the critical bus must maintain a 250 MVAR reactive margin from the point of instability (nose of the QV curve) with successful remedial action scheme operation. The Goshen 345 kV bus is typically the critical bus where the 250 MVAR reactive margin is applied for loss of the Jim Bridger-Borah 345 kV line.

For double contingency (N-2) in the Jim Bridger transmission system, a 200 MVAR reactive margin must be maintained at the critical busses in the Idaho Power transmission system (Borah and Kinport 345/230 kV busses), and a 125 MVAR

10


reactive margin must be maintained at the critical busses in the PacifiCorp transmission system (Bridger and Goshen 345 kV busses).

Generation deficiencies, when sufficient, will be allocated amongst all the generating units within the WECC interconnected system, in accordance with inertia, governor droop settings or PMAX. Area interchange controls will be blocked.

Generator reactive capability limits will be honored.

Transformer taps, phase shifters and DC converter taps will be assumed to operate in automatic mode, if so equipped.

No manual (local/remote) reactor or capacitor switching occurs in the Bridger transmission system during the post-transient period. However, shunt devices equipped with automatic switching controls and so represented in the power flow case for other WECC systems will be assumed to operate in automatic mode.

Loss of any one of the 345 kV Bridger lines or the Bridger-Rock Springs 230 kV line will initiate the following remedial action scheme: Switching in a 175 MVAR shunt capacitor bank at Kinport 345 kV at ten cycles, bypassing the Burns series capacitor bank and switching in a 50 MVAR shunt capacitor bank at Goshen 161 kV at 12 cycles, and switching in an additional 50 MVAR shunt capacitor bank at Goshen 161 kV at 42 cycles. Cycles are counted from the fault inception.

Line and transformer loadings will not exceed emergency ratings.

11

Documents

Reliability Criteria For System Planning - OATI webOasis · Web viewThe reliability criteria define the performance requirements for planning the IPCo system. The performance requirements