ATC 10 Year Assessment – 2018

2018

10-Year
Assessment

System performance criteria

System performance over a ten year planning horizon will be assessed at least annually. Such assessments will involve steady state simulations and, as appropriate, dynamic simulations.

Steady State Assessments Overview

Steady state assessments include the consideration of the following system load conditions.

  1. Summer peak
  2. Summer 90/10 proxy peak
  3. Summer off-peak
  4. Winter peak
  5. Fall/spring off-peak
  6. Light load
  7. Minimum load

At a minimum, two of the first three load conditions or similar models will be assessed in all long-range planning studies. The last four load conditions may be considered when more detailed analyses are being conducted of specific alternatives developed to solve a particular problem. The steady state load conditions have the following general applications.

1.  Summer peak

Used to determine summer peak load serving and regional supply limitations, including voltage security assessments.

2.  Summer 90/10 proxy peak

Used considering the P1 and P2 Contingencies (loss of single element) analysis to help us determine whether extreme weather conditions may require unusual measures to meet unexpected load. The 90/10 proxy forecast will be used to help prioritize and stage projects but it will not necessarily be used as the sole reason to justify projects or required in service dates.

3.  Summer off-peak

Used to evaluate Contingencies where transmission equipment may be intentionally outaged at appropriate load levels in addition to assessing system biases or high system imports into the ATC system.

4.  Winter peak

Used to determine winter peak load serving limitations.

5.  Fall/spring off-peak

Used to evaluate Contingencies where transmission equipment may be intentionally outaged at appropriate load levels to identify seasonal regional transfer impacts.

6.  Light load

Used to study the possibility of high voltages on the power system, impact of capacitor switching, and potential equipment overloads near base load power plants due to reduced local demand at light load levels. The light load case represents many more hours in the year than the minimum load model.

7.  Minimum load

Used to review the expected voltage range at distribution interconnection points and for determination of adequate voltage control at minimum load levels. Typically the highest bus voltages will occur with an intact transmission system during minimum load conditions. Steady state performance assessments incorporating Operating Guides are done to identify potential transmission system vulnerabilities over a reasonable range of future scenarios. The steady state system performance criteria to be utilized by ATC for its assessments shall include the following conditions. (Applicable NERC Standard: TPL-001-4, R2.1, R2.2, and R3)

Normal Intact Conditions (P0 Contingency)

No transmission element (BES and 69-kV transmission circuits, transformers, etc.) should experience voltage levels outside of applicable voltage limits or loading in excess of its applicable normal thermal ratings for P0 Contingency conditions. This criterion should apply for a reasonably broad range of forecasted system demands and associated generation dispatch conditions. The Normal Intact Conditions shall include the following additional considerations.

  1. The normal voltage limit range is typically 95 percent to 105 percent of nominal voltage for P0 Contingency conditions. Such measurements shall be made at the high side of transmission-to-distribution transformers. Voltage levels that differ from this range will be considered, if they are acceptable to the affected transmission customer or needed to address specific ATC equipment limitations. Exceptions for certain interconnected entities are evaluated accordingly (e.g., agreements implemented for NERC standard NUC-001). All voltage limits should be met with the net generator reactive power limited to 90 percent of the reported maximum reactive power capability.
  2. The steady state voltage  should be stable at all ATC buses for normal intact system configurations and for a reasonably broad range of forecasted system demands and associated generation dispatch conditions.
Single Contingency Conditions (P1 and P2 Contingencies)

No transmission element should experience any of the following system conditions:

  • voltage levels outside of applicable voltage limits,
  • loading in excess of its applicable thermal emergency ratings, and
  • post-Contingency voltage deviation (percent change of actual pre-Contingency and post contingency steady state voltage) of greater than 10%.

This criterion is applicable for the following individual Contingencies at appropriate load levels: P1, P2, and maintenance outage (planned single element outage excluding buses and breakers) followed by a P1 Contingencies. This criterion should be applied for a reasonably broad range of forecasted system demands and associated generation dispatch conditions. Refer to the table in General Steady State Performace Criteria section regarding the utilization of load curtailment in planning studies. Field switching may not be considered as acceptable measures for achieving immediate overload relief for breaker-to-breaker Contingencies. For restoration after breaker-to-breaker Contingencies, field switching, Load Tap Changer (LTC) adjustments, Operating Guides and/or generator redispatch may be considered as acceptable measures to bring element loading levels below appropriate limits. The transmission element loading should be reduced within the applicable rating and its associated timeframe.

For assessments conducted using applicable Midwest Reliability Organization (MRO) and ReliabilityFirst (RF) region-wide firm load and interchange levels (i.e. no market or non-firm system bias), generator real power output should not be limited under P1 and P2 (excluding P2.2 HV, P2.3 HV, and P2.4) Contingencies.

The Single Contingency Conditions shall include the following additional considerations.

  1. System design should ensure that loading can be adjusted to observe a reliable state within 30 minutes or any Interconnection Reliability Operating Limit Tv, whichever is less (IROL Tv: The maximum time that an Interconnection Reliability Operating Limit can be violated before the risk to the interconnection or other Reliability Coordinator Area(s) becomes greater than acceptable. Each Interconnection IROL Tv shall be less than or equal to 30 minutes [from NERC Glossary of Terms]). Temporary excursions above the applicable thermal emergency ratings are acceptable if a Special Protection System (SPS) will reduce loadings automatically (i.e. no manual intervention) to acceptable loading levels in the applicable timeframe. The acceptable loading levels after SPS operation cannot exceed the applicable thermal emergency ratings. The applicable timeframe is determined by the type of limitation that will occur if left unmitigated (e.g., clearance limitation may take several minutes whereas exceeding a relay trip setting may result in an essentially instantaneous trip).
  2. Under applicable P1, P2, and maintenance outage (planned single element outage excluding bus and breaker) followed by a P1 Contingencies at appropriate load levels, the temporary acceptable voltage level must be within the applicable voltage The acceptable temporary voltage range is typically 90 percent to 110 percent of the system nominal voltage. Voltage levels that differ from this range will be considered, if they are acceptable to the affected transmission customer or needed to address specific ATC equipment limitations. Voltage levels more restrictive than this range will be considered to address specific equipment limitations. Exceptions for certain interconnected entities are evaluated accordingly (e.g., agreements implemented for NERC standard NUC-001). Load shedding or field switching is not an acceptable measure for achieving immediate voltage restoration for breaker-to-breaker Contingencies. However, for full or partial restoration of load after the event, field switching, LTC adjustments, Operating Guides and/or generator redispatch may be considered as acceptable measures to bring voltage levels within appropriate limits. The applicable voltage limits are screened with the net generator reactive power limited to 90 percent of the maximum reactive power capability. For Categories where load curtailment is acceptable, consideration may be given to operating procedures that are designed to shed a minimum amount of load. Refer to the table in Section 1.1.6 regarding the utilization of load curtailment in planning studies.
  3. System design should ensure that voltage levels outside of any IROL can be restored to achieve a reliable state within 30 minutes or any IROL Tv, whichever is less. These voltage limits are screened with the net generator reactive power limited to 90 percent of the applicable maximum reactive power capability. Temporary voltage excursions outside the range of applicable high and low voltage limits are acceptable if a Special Protection System (SPS) or control of shunt compensation will automatically (i.e. no operator intervention) restore system voltage to temporary acceptable voltage levels within the applicable timeframe. The applicable timeframe will be situation dependent and may need to be reviewed with Asset Planning & Engineering.
  4. The steady state voltage should be stable at all ATC buses for applicable P1, P2, and maintenance outage (planned single element outage excluding bus and breaker) followed by a P1 Contingencies; at appropriate load levels, for a reasonably broad range of forecasted system demands and associated generation dispatch conditions.
  5. Transmission elements that experience loading in excess of applicable thermal emergency ratings for applicable P1, P2, and maintenance outage (planned single element outage excluding bus and breaker) followed by a P1 Contingencies; at appropriate load levels, should be evaluated in accordance with an applicable Cascading trip threshold to determine the consequence of the contingent event.
Multiple Contingency Conditions (P3 through P7 Contingencies)

No transmission element should experience either of the following system conditions:

  • voltage levels outside of applicable voltage limits or
  • loading in excess of its applicable thermal emergency ratings.

This criterion is applicable for applicable P3 through P7 Contingencies. This criterion should be applied for a reasonably broad range of forecasted system demands and associated generation dispatch conditions. Overload relief methods may include supervisory controlled or automatic switching of circuits, or generation redispatch. Refer to the table in Section 1.1.6 regarding the utilization of load curtailment in planning studies. The transmission element loading should be reduced within the applicable rating and its associated timeframe. The Multiple Contingency Conditions shall include the following additional considerations.

  1. Under applicable P3 through P7 Contingencies, the temporary acceptable voltage level must be within the applicable voltage limits. The acceptable temporary voltage range is typically 90 percent to 110 percent of the system nominal voltage. Voltage levels that differ from this range will be considered, if they are acceptable to the affected transmission customer or needed to address specific ATC equipment limitations. Voltage levels more restrictive than this range will be considered to address specific equipment limitations. Exceptions for certain interconnected entities are evaluated accordingly (e.g., agreements implemented for NERC standard NUC-001). Methods of restoration to normal voltage range may include supervisory control of the following: capacitor banks, LTCs, generating unit voltage regulation, generation redispatch, or line switching. Refer to the table in Section 1.1.6 regarding the utilization of load curtailment in planning studies. The applicable voltage limits should be met with the net generator reactive power limited to 90 percent of the applicable maximum reactive power capability. For Categories where load curtailment is acceptable, consideration may be given to operating procedures that are designed to shed a minimum amount of load.
  2. The steady state voltage should be stable at all ATC buses for applicable P3 through P7 Contingencies for a reasonably broad range of forecasted system demands and associated generation dispatch conditions.
  3. Transmission elements that experience loading in excess of applicable thermal emergency ratings for applicable P3 through P7 Contingencies should be evaluated in accordance with an applicable Cascading trip threshold to determine the consequence of the contingent event.
Extreme Disturbance Events (TPL-001-4 Table 1 Steady State Events)
  1. The NERC Steady State Extreme Events that are expected to produce more severe system impacts should be evaluated to determine potential system impacts and vulnerabilities. If widespread Cascading may occur, then an evaluation of possible actions that would reduce the likelihood or mitigate the consequences of the extreme event should be performed.
  2. Transmission elements that experience loading in excess of applicable thermal emergency ratings for applicable NERC TPL-001-4 Table 1 Steady State Contingencies should be evaluated in accordance with an applicable Cascading trip threshold to determine the consequence of the contingent event.
Planning Horizon Steady State Voltage Stability
  1. The nose of the steady state bus P-V curve should be at or below the applicable bus voltage limit as coordinated with the applicable Planning Coordinator and/or by any applicable Transmission Owner(s) (e.g., the MWEX limitation of 95 percent of nominal voltage at the Arrowhead 230-kV bus) to assure adequate system voltage stability and reactive power resources for P0 through P7 Contingencies. Different values may be appropriate for areas of the system that contain fast acting reactive power devices (e.g., FACTS devices). If additional voltage stability limitations are discovered on the ATC system, then further analysis will be conducted to determine the appropriate course of action based on the probability and impact of the situation.
  2. The steady state operating point at all ATC buses should be at least 10 percent away from the nose of the bus P-V curve and above the applicable low voltage limit to assure adequate system voltage stability and reactive power resources for P0 through P7 Contingencies. The pre-Contingency voltage stability margin should be adequate to avoid voltage instability for the most severe applicable Contingency. This 10 percent voltage stability margin is chosen to reflect uncertainties in load forecasting and modeling, as well as to provide a reasonable reliability margin. Exceptions to the 10 percent margin requirement may be granted if there are feasible system adjustments which can reliably restore the 10 percent margin post contingent within 30 minutes.
  3. Dynamic voltage stability must be assessed to determine whether voltage instability (collapse) may occur during the transition from acceptable steady state pre-contingent (P0 Contingency) voltage stability to acceptable steady state post-contingent (P1 through P7 Contingencies) voltage stability.
  4. Steady state voltage stability assessments are performed on a selective basis using engineering judgment, when ATC bus voltages are found to be at or below the low voltage limit at multiple buses in a common geographic area when performing other steady state analyses over a broad range of forecasted system demands and associated generation dispatch conditions. Otherwise, acceptable steady state voltage stability is assumed to exist.

System design as planned should ensure that exceeding any steady state voltage IROL can be mitigated within 30 minutes or any IROL Tv, whichever is less. Temporary excursions above the applicable voltage stability limit are acceptable if a Special Protection System (SPS) will automatically (i.e. no manual intervention) return the system to an acceptable stability condition in an acceptable timeframe.

 General Steady State Performance Criteria(1,2)

 Contingency Definitions

Dynamic Stability Assessments Overview

The dynamics cases are built to be consistent with the regional dynamics database except for the load modeling, which may consist of appropriate load and motor modeling for voltage stability assessments. Dynamic stability assessments will include consideration of the following system load conditions.

  1. Summer peak
  2. Light load

The dynamic load conditions have the following general applications.

1. Summer peak

This load condition is typically used for voltage stability studies to determine whether system disturbances during peak load conditions cause voltage instability. Also, since the performance of wind generators is more closely linked to system voltage performance, summer peak cases should be considered when assessing the performance of wind generation.

2.  Light load

This load condition is typically used for dynamic stability assessments in order to assess the angular stability of synchronous machines (e.g. fossil fuel generators). Empirically, it is noted that the dynamic performance of synchronous machines is worse in lighter load conditions likely due to lower field excitation current.

Transient and dynamic stability assessments of the planning horizon are generally performed by the System Planning Department to assure adequate avoidance of loss of generator synchronism, prevention of system voltage collapse, and system reactive power resources within 20 seconds after a system disturbance. The transient and dynamic system stability performance criteria to be utilized by ATC for planning purposes shall include the following factors. (Applicable NERC Standard: TPL-001-4, R2.4, R2.5, and R4)

Large Disturbance Stability Performance Assessment
  1. For generator transient stability, faults will be modeled on the high side bus at generating plants.
  2. For generating units with actual “as built” or “field setting” dynamic data, a 0.5 cycle margin will be added to the expected clearing time (ECT) for dynamic Contingency simulations. For generating units with assumed, typical, or proposed dynamic data, a 1.0 cycle margin will be added to the ECT for dynamic Contingency simulations. The total clearing time (ECT + margin) must be equal to or less than the calculated critical clearing time (CCT) from the simulation.
  3. Generator transient stability will be demonstrated for at least one key Contingency for each applicable P1 through P7 Contingency. Unacceptable transient stability performance occurs when any of the stability assessment criteria are not met.
    1. Angular stability assessment
      • Generating unit loses synchronism with the transmission system, unless it is deliberately islanded
      • Cascading tripping of transmission lines or uncontrolled loss of load
      • Poorly damped angular oscillations where acceptable damping is defined below
    2. Voltage stability assessment
      • Transient stability voltage response at applicable Bulk-Electric System (BES) buses serving load shall recover to at least 80% of nominal voltage within 2 seconds of the initiating event for all P1-P7 Contingencies
      • For voltage swings subsequent to fault clearing and the first voltage recovery above 80%, voltage dips at each applicable BES bus serving load shall not dip below 70% of nominal voltage for more than 30 cycles or remain below 80% of nominal voltage for more than 2 seconds for all P1-P7 Contingencies
  4. Where needed system reinforcement cannot be implemented in an appropriate timeframe, then a corrective plan must be established in order to respect System Operating Limits and/or Interconnected Reliability Operating Limits. Where appropriate, corrective plans may include generator redispatch, operating guides, and/or Special Protection Systems.
Angular Oscillation Damping

Well damped angular oscillations need to meet one of the following two criteria.

  1. The generator rotor angle peak-to-peak magnitude is within 1.0 degree or less at 20 seconds after the switching event.
  2. The generator average damping factor for the last five cycles of the 20 second simulation is 15.0 percent or greater after the switching event.

Average Damping Factor (%) = ((d1+d2+d3+d4)/4) x 100 Where dn = (1-SPPRn) where SPPRn  (Successive Positive Peak Ratio) is the ratio of the peak-to-peak amplitude of a rotor angle swing (nth cycle back from the 20 second simulation time) to the peak-to-peak amplitude of a rotor angle swing on the previous cycle (n+1th cycle back from the 20 second simulation time).

d4 = 1 – p4/p5, d3 = 1 – p3/p4, d2 = 1 – p2/p3, d1 = 1 – p1/p2

click here for a small disturbance example

Extreme Disturbance Events (NERC Standard TPL-001-4 Table 1 Stability Extreme Events)

The NERC Stability Extreme Events that are expected to produce more severe system impacts should be evaluated to determine potential system impacts and vulnerabilities. If widespread Cascading may occur, then an evaluation of possible actions that would reduce the likelihood or mitigate the consequences of the extreme event should be performed.

Voltage flicker

The criteria for acceptable voltage flicker levels are defined by the requirements of regulatory entities in the states in which ATC owns and operates transmission facilities, IEEE recommended practices and requirements, and the judgment of ATC. The criteria are described below.

The following flicker level criteria are to be observed at minimum nominal system strength with all transmission facilities in service. Minimum nominal system strength shall be defined as the condition produced by the generation that is in service in the Minimum load models, minus any generation that is:

  1. Electrically close to the actual or proposed flicker-producing load
  2. Could significantly affect flicker levels
  3. Could reasonably be expected to be out of service under Minimum load conditions

Although the limits described below are not required to be met during transmission system outages, if these limits are exceeded under outage conditions, the flicker producing load must be operated in a manner that does not adversely affect other loads. Planned outages can be dealt with by coordinating transmission and flicker producing load outages. Because operating restrictions during unplanned outages may be severe, it would be prudent for the owner of the flicker producing load to study the effect of known, critical, or long term outages before they occur, so that remedial actions or operating restrictions can be designed before an outage occurs. During outages, actual, rather than minimum nominal, system strength should be considered.

All ATC buses are required to adhere to the following two criteria.

  • Relative steady state voltage change is typically limited to 3 percent of the nominal voltage for intact system condition simulations. For new projects, it is also typically limited to 5 percent of the nominal voltage under outage conditions. The relative steady state voltage change is the difference in voltage before and after an event, such as capacitor switching, load switching or large motor starting (not including Contingency events). These events should occur at least 10 minutes apart and take less than 0.2 seconds (12 cycles) to go from an initial to a final voltage level.
  • Planning levels are to be limited to a short term perception (Pst) of 0.8 and a long term perception (Plt) of 0.6. Pst and Plt are calculated using the calculation methods outlined in IEEE standard 1453-2015.

Harmonic Voltage Distortion

In general, it is the responsibility of ATC to meet harmonic voltage limits and the responsibility of the load customers to meet harmonic current limits. Usually, if harmonic current limits are met, then harmonic voltage limits will also be met. The level of harmonics acceptable on the ATC system is defined by state regulations, IEEE Standard 519-2014 (Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems) and the judgment of ATC. The voltage distortion limits and current distortion limits are specified in the Tables 1-4 below.

The observance of harmonic limits should be verified whenever a harmonic related problem is discovered or a new harmonic producing load with a reasonable possibility of causing harmonic problems is connected to the ATC system. The following process is utilized by ATC when managing an existing harmonic-related problem or a new harmonic-producing load:

Existing problems – When a harmonic related problem is found on the ATC system, it is ATC’s responsibility to determine the source of the harmonics. If harmonic current limits are violated, the source of the harmonics will be required to decrease their harmonic currents to below the limits. If, after the harmonic current has been reduced to an acceptable level, the harmonic voltage is still causing a problem and above specified levels, it shall be the responsibility of ATC to bring the harmonic voltages within limits. If limits are not violated and there is still a harmonic related problem (an unlikely situation), it is the responsibility of the entity experiencing the problem to harden its equipment to the effect of harmonics or reduce the harmonics at their location. An existing violation of these harmonic limits that is not causing any problems does not necessarily require harmonic mitigation.

New harmonic producing loads – It is the responsibility of any customer wanting to connect a harmonic producing load to the ATC system to determine if the proposed load will violate the harmonic current limits and, if these limits are violated, to determine and implement steps necessary to reduce the harmonic currents to acceptable levels. If harmonic voltage limits are not met after harmonic current limits have been met, it is the responsibility of ATC to determine if the harmonic voltage distortion will cause any system problems and if they will, it is ATC’s responsibility to develop and implement a plan to meet the harmonic voltage limits.

Under-Frequency Load Shedding

Under-frequency load shedding (UFLS) island identification is based on the following criteria. In general, UFLS is designed to arrest declining frequency after an under frequency event. Island identification is the subdivision of the Bulk Electric System (BES) including the ATC transmission system into sub regions. UFLS analysis falls into two categories; frequency performance and dynamic volts per hertz performance.

Island Identification

The identification of UFLS islands is based on the NERC reliability standard PRC-006. The UFLS island identification that ATC uses is based on the following four criteria:

  1. Actual Historical Island Event: A UFLS island is identified as a portion of the BES including the ATC transmission system which was an actual historical island event within the past five years.
  2. Non-UFLS System Studies: A UFLS island is identified as a portion of the BES including the ATC transmission system which was determined to be an island through non-UFLS system studies.
  3. Relay Scheme or a Special Protection System: A UFLS island is identified as a portion of the BES including the ATC transmission system which is planned to detach from the transmission system as a result of the operation of a relay scheme or a special protection system.
  4. Large Single Island: A UFLS island is identified as a single island in the MRO area, the RF area, or the Eastern Interconnection that includes the entire ATC transmission system. The island shall be selected by applying the above criteria and coordinating with the criteria of MISO and PJM to verify that all ATC UFLS schemes meet the PRC-006 standard performance requirements when acting together with or without the programs of the BES.
Frequency Performance Assessment Criteria

Transient island frequencies shall remain within the Under-frequency and Over-frequency Performance Characteristic Curves in PRC-006 Standard Attachment 1.

Volts Per Hertz Assessment Criteria

Transient Volts per Hertz values shall not exceed 1.18 per unit for longer than two seconds cumulatively per simulated event, and shall not exceed 1.10 per unit for longer than 45 seconds cumulatively per simulated event at each generator bus and generator step-up transformer high-side bus.

Generating Facility Power Factor and Voltage Regulation

Power Factor

Power Factor Requirements for Interconnection Generating Units are as follows. ATC’s standard power factor range for synchronous and non-synchronous (e.g. wind turbines, solar) generation is 0.95 leading (when a Generating Facility is consuming reactive power from the Transmission System) to 0.90 lagging (when a Generating Facility is supplying reactive power to the Transmission System). These values have been approved by the FERC for use by ATC (cf. FERC Orders ER05-1475 and ER06-866).

Static reactive power sources can only be used to make up for losses between the machine terminal and the POI for synchronous machines and losses between the terminal of the machines and the high side of the GSU for non-synchronous machines. All other reactive power to meet the power factor requirement must be provided by continuous and sustainable dynamic sources. Operation across the entire power factor range must be fully dynamic, variable, and capable of sustained indefinite operation.

Static sources can be switched on or off in the range of seconds and provide reactive power in large discrete blocks. Cap Banks are considered static sources of reactive power.

Dynamic sources can provide variable amounts of reactive power in a few milliseconds. Static Var Compensators (SVCs), Static Synchronous Compensators (STATCOMs), Flexible AC Transmission Systems (FACTS), inverters, and synchronous condensers are all considered dynamic sources of reactive power.

The Generating Facility must be capable of maintaining ATC’s standard power factor range at all power output levels by providing continuous dynamic reactive power at the following locations:

a) The Point of Interconnection (POI) for all synchronous generators

For synchronous machines, the interconnection studies will account for the net effect of all energy production devices and losses on the Customer’s side of the POI.

b) The high-side of the generator step up (GSU) for all non-synchronous generators (FERC Order No. 827)

For non-synchronous machines, the interconnection studies will account for the net effect of all energy production devices and losses on the Customer’s side of the GSU.

Dynamic reactive power provided by the non-synchronous generators must meet the following requirement from FECR order 827 Item 35:

“Non-synchronous generators may meet the dynamic reactive power requirement by utilizing a combination of inherent dynamic reactive power capability of the inverter, dynamic reactive power devices (e.g., Static VAR Compensators), and static reactive power devices (e.g., capacitors) to make up for losses.”

POI Voltage

The interconnecting generator must be capable of automatically and dynamically maintaining a POI voltage schedule that is specified by the Transmission Operator. Any generator interconnected within the ATC system is expected to maintain a voltage schedule (voltage setpoint) of 1.02 p.u. at its POI, within limits of its reactive capabilities, to facilitate transmission operations reliability under normal system conditions (system intact) and contingency conditions, unless another voltage level is communicated to the generator by the ATC Transmission Operator (cf. NERC Reliability Standard VAR-001).

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