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Question 1  (41 Responses)
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Question 2  (42 Responses)
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Question 3  (31 Responses)
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Question 3 Comments  (44 Responses)
Question 4  (39 Responses)
Question 4 Comments  (44 Responses)
Question 5  (38 Responses)
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Question 6  (38 Responses)
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Question 6  (34 Responses)
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Question 7  (0 Responses)
Question 7 Comments  (44 Responses)
Question 8  (0 Responses)
Question 8 Comments  (44 Responses)
Question 9  (38 Responses)
Question 9 Comments  (44 Responses)
 
Individual
Jinhui Zhang
Converteam Naval Systems Inc.
No
I believe it should be applicable to both.
Yes
 
 
 
No
please see my further comments on this.
No
 
Yes I agree with the approach
 
Yes
 
 
 
Yes
0. (Overall) This is a good document that has good background study and contains a lot of expertise; 1. (Voltage definition inconsistency)In the LVRT curves, it talks about the voltage at the point of interconnection. However, in R2.1 it uses voltage at the generator terminals. I think there is a little inconsistency between these two. It would be good to just use one of them, preferably the former one. The reason is that different generator plants might have different impedance between the generator terminals and the points of interconnection, so defining the voltage at the terminals poses a little unfairness. Another part of the reason is that for transmission protection purpose, it should ends at the point of interconnection. 2. (Voltage range inconsistency)The voltage range is 0.9-1.1pu in the VRT curve, but it says 0.95-1.05 in R2.1. It would be good to make it consistent. 3. (Date point missing) In the table supporting the VRT curves, the 0.95 and 1.05pu data are missing. 4. (Priority) WECC and MRO have different VRT curves. Which one will override which one at the end? Will the NERC PRC-024 take priority than the Regional Entities? 5. Was reactive power support during faults considered in the draft group? Will it be required in the future? Thanks
Individual
Jianmei Chai
Consumers Energy Company
Yes
 
Yes
 
No
Consumers Energy doesn't have generating units that cannot meet the thresholds. However, we would like to offer the following comments: The Standards Drafting Team should be congratulated for the excellent curves in Attachment 1. A review of our fleet which contains units of several vintages, manufactured by General Electric, Westinghouse, Siemens, and Allis-Chalmers, shows that turbine-generators from all of these manufacturers comply with these curves. To assist Generator Owners and Compliance Auditors, the SDT should furnish mathematical formulae for the "slanted lines" in the curves. Should a Generator Owner elect to set an underfrequency relay at 120 seconds and 59.1 Hz, there might be uncertainty or disagreement about compliance, depending upon how the interpolation of the graph is viewed. Interpolation from a semi-log plot is often not easy. This uncertainty can and should be eliminated by including the two formulae in Attachment 1.
 
Yes
 
Yes
We believe this is sufficient to address the concern if this picks up the wind farms that are a growing part of generating capacity.
Yes I agree with the approach
 
Yes
 
No.
No.
Yes
Please see comments on Question 3.
Group
Entergy Fossil Operations
Stan Jaskot
Entergy Fossil Operations
Yes
Generator Owner is responsible for the maintenance of the facility. Relay settings are a Generator Owner function.
No
I disagree in principle that NERC is dictating how generator protective relays are set. These relays are set to protect the generation equipment and ensure long term reliability of the unit. Dictating settings which enhances ride through capability ensure short term reliability and can hurt long term reliability. If this if force upon us, I agree with only addressing the voltage and frequency generator protective relays.
No
 
 
Yes
I do not know enough about this to comment either way
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
Yes
Do away with this standard.
Group
NERC System Protection and Control Subcommittee (SPCS)
John Ciufo - SPCS
Hydro One
Yes
 
No
PRC-024 should only apply to non-synchronous machines. The SPCS believes that coordination of synchronous generator voltage and frequency protective relays with transmission relays should not be addressed in PRC-024. An effort is underway to address coordination of generator voltage and frequency protective relay settings with transmission protection systems either by modifications to PRC-001 or the development of a new SAR to address coordination requirements. SPCS is preparing a Technical Reference paper on such coordination that is expected to be completed in June, 2009. Generator voltage and frequency protective relays are included in that that paper. The purpose as stated in the SAR is "To ensure that generators will not trip off-line during specified voltage and frequency excursions." The Standard will not accomplish its stated purpose by limiting requirements to generator protective relays alone. In fact it may actually have the exact opposite consequence. Undervoltage relays are not usually set on most synchronous generators. When undervoltage relays are applied, IEEE C37.102 recommends alarm rather than trip. The more likely cause for the loss of a generator due to a dip in voltage is from the loss of equipment on the auxiliary bus. This was the cause sited for a well documented event on March 27, 1994 losing all generating units at Cinergy's Gibson Station. Other events since 1994 were also due to tripping of generators due to loss of auxiliary busses caused by voltage dips from system faults. In fact, the Standard may result in the unintended consequence of reducing reliability. Many generator owners may take the recommendation as an implied directive to set previously unused generator undervoltage relay elements to the minimums stated in the Standard. That would cause more generator trips for system faults rather than fewer trips. Similarly, many generators that currently do not have undervoltage relay settings would trip at various other inherent voltage levels during a voltage excursion. With all of them set at or about 0.90 per unit, they would all trip at the same point, causing a catastrophic loss of generation. There are significant machine protection issues which are not addressed, such as the Volts/Hertz relay which protects the machine from an over-fluxing thermal hazard. Loss of generation consequential to problems on auxiliaries is a significant problem, which is not addressed in this Standard.
 
 
No
FERC 661-A is a wind generator facility ride-through performance criterion, not a synchronous generator relay setting requirement. They cannot be compared as being equivalent. A synchronous generator undervoltage capability will be quite different from an entire wind facility undervoltage ride-through capability. The 9 cycle zero voltage interval is inadequate. The 9 cycle setting would cover for most normally cleared faults but generators must also remain on line through faults with delayed clearing due to breaker failure as required in the NERC TPL Standards. The time interval for such clearing is more typically 12 to 15 cycles. This time delay can increase to 0.5 seconds if high speed protection is out of service, for example a single relay communication channel, at the time of a fault and the fault is then cleared in zone 2 time. SPCS believes that R.R.1 is worded in a confusing way. It implies that you had to trip in 9 cycles or less – rather than not trip for a minimum of 9 cycles- albeit we want to wait longer than that. SPCS respectfully questions whether it is conceptually possible to properly state these criteria as a single curve. It is more appropriate to have separate requirements for wind generation and other generators. Additionally, they should differ related to points of interconnections (a contractual arrangement), and refer to the high-side of the GSU for all other generation. This would lend consistency and avoid unnecessary confusion. There are a number of important issues that arise with current approach, including:  In general, generator protection should not trip generators on UV, but should alarm, as stated in IEEE C37.102. Please also see latest C50.12 and C50.13. UV is generally a thermal consideration and an alarm is more appropriate to call operator attention to a malfunction.  The existence of a curve such as this in a NERC Standard will lead to generator owners enabling UV relays to trip and setting them per the curve, which is a serious danger to system reliability.  For some specific situations such as unmanned hydro units, tripping on time-UV may be considered.  The idea of a ride-through curve originated with wind farms, and is not generally conceptually appropriate for other generators. For example, this approach is not conceptually appropriate for cylindrical rotor synchronous machines.  The Voltages presented are at the point of interconnection and are not directly translatable to machine relay voltage settings.  Machine Volts/Hertz curves are a significant issue and are not addressed.  The UV performance of plant auxiliaries is a significant issue, and is not addressed.  The standard should be very clear to discourage plant owners from setting under- and over- voltage relays if they don't already have them, or need them for very specific situations. SPCS also is concerned because it appears the SDT has considered only the positive sequence voltage in developing the curves in Attachment 2. Overvoltage relays measure individual phase-to-ground or phase-to-phase quantities and SPCS expect that generator owners will apply these curves based on the quantities measured by the relays in developing relay settings. As such, the curves must be based on the quantities that are measured by protective relays and the quantities must be clearly stated. To highlight our concern, consider that for a line-to-ground fault at the point of interconnection on an effectively grounded system the unfaulted phases may have fundamental frequency voltages of 125% or more for the duration of the fault. Under such conditions generators with overvoltage relays set per the curve may trip at 120% voltage prior to clearing the fault from the transmission system. Under these conditions tripping is not required for generator protection and may have a detrimental impact on system reliability, yet it is permissible per the proposed curve. There is guidance in the industry and C37.102 to provide dielectric (insulation) protection for extremely high voltages, however 120 % voltage is overprotecting the generator. For Generator protection, the first line of defense is generator surge arrestors but some units may also use a high set overvoltage protection as well. This voltage is a much higher level then 120% shown in the curve (i.e. 150% of rated voltage). Voltage relays applied to the system side of the generator step-up transformer should be configured and set in such a way that they do trip the generator for higher voltages on unfaulted phases for phase-to- ground faults. As you may know generator windings are sometimes tested with high potential: New machines can be tested as high as twice (200%) rated line-to-line voltage plus 1000 Volts (Commissioning High Pot) for one minute. Older Machines that are in service for significant time can be tested at 125% to 150% of rated line-to-line voltage (Maintenance High Pot) for one minute. There are some industry differences of opinion on this topic of course but 120% instantaneously is too low. Voltage settings are based on type of insulation material (Class F is in common present days) and its thickness. A curve would need to be developed that takes insulation thickness into account. USBR's practice is to use manufacture designed 105% continuous. Then, 59 is set a 110% of 105% (continuous use) for time coordination (TOV) and 130% of 105% of phase-to-ground voltage for instantaneous (IOV).
No
The interconnection Voltage is not relevant, only the amount of generation potentially lost to the system.
 
 
The FRCC UFLS has a requirement for generators to remain on line for 1 second with frequency down to 57.5 Hz. Regional differences are developing as the Regions perform studies to current UFLS strategies while considering the coordination requirements of generator underfrequency tripping. To date, NPCC and FRCC may be the only regions that have completed their studies. It is recommended that PRC- 024-1 wait on going forward in the standards process until the regions conclude their studies and develop their requirements based on their particular portions of the interconnected power system.
 
Yes
PRC-024 should only apply to non-synchronous machines. Coordination of synchronous generator voltage and frequency protective relay settings with transmission protection systems should be addressed along with all other coordination in PRC-001 – Protection coordination. SPCS is preparing a Technical Reference paper on such coordination that is expected to be completed in June, 2009. Generator voltage and frequency protective relays are included in that that paper. The Attachment 2 voltage ride through curve was developed, to SPCS’ understanding, by compiling a number of system events delineating those events whereby the tripping of generators would exacerbate the event. It does not appear that the SDT analyzed data from the August 14, 2003 Northeast Blackout. Actual data from the event in Michigan, before the system cascaded and broke apart revealed 345 kV system voltages of less than 0.9 per unit. Some generators in Michigan tripped by undervoltage relays set at 0.9 per unit that significantly accelerated the cascade. Even those generators along the western fringe of the soon-to-be separated power system were of event more concern; data indicated these large units were experiencing 345-kV voltages of less than 0.9 per unit. Those generators did not trip because they did not have undervoltage relaying set to trip. Had these units tripped on undervoltage relaying, the event would have extended much further to the west of the actual impacted area. The Standard requires generator relays to be set based on a voltage at the interconnection point to the BES. However the relays are typically connected to a voltage source at the generator, not the BES interconnection. The translation from generator terminal voltage to a point of interconnection voltage is not a direct relationship. It will vary depending upon the assumption made for generator real and reactive output, or the distance to the “point of interconnection.” The Standard gives no direction regarding these assumptions. The voltage to be sensed must be the generator terminal voltage. IEEE C50.13 describes the standards to which the modern generators were built. This standard recommends reducing unit output after ascertaining the presence of an undervoltage alarm. This standard does not recommend unit tripping. Totally different relay settings will be obtained with different generator output assumptions. This lack of consistency will make it impossible to determine if compliance to the Standard is achieved. SPCS also have concerns with the overfrequency curve in Attachment 1 in light of the August 14, 2003 Northeast Cascade and Blackout. During the sequence of events an island formed consisting of portions of western New York and eastern Ontario with a significant generation-load mismatch. The surplus generation in the island resulted in an overfrequency condition to which several large generating units responded to arrest the overfrequency at 63 Hz. Had those units been set to trip on the proposed curve on August 14, the units would have tripped prematurely potentially leading to a collapse of the island. While the overfrequency curve may be acceptable as a floor for setting the overfrequency relays, there should also be a requirement to coordinate the overfrequency tripping with the unit controls and unit capability to maximize the ability of machines to control overfrequency while operating within their capability. Undervoltage alarms as experienced by hydro, fossil, combustion, and nuclear units are an indicator of possible thermal issues within the generator. Other alarms from RTDs and hydrogen pressure are better indicators. Manufacturers recommend operator action up to and including reduction in unit output rather than a unit trip. Tripping units on undervoltage is not recommended by the IEEE C37.102 standard on generator protection. Rather C37.102 also recommends alarm. Each type of unit, hydro, fossil, nuclear, combustion, and renewable generator have different thermal issues relating to system undervoltage. A single curve over-simplifies the issue to the point that system reliability is degraded. If any curve is included, it should be focused only on wind turbines as they have voltage ride through controls. Attachment 2 requires voltage evaluation at the system voltage level. Concerning Attachment 1, SPCS believes this is mainly present to insure that generator tripping will not interfere with UFLS programs. There should be a statement that settings should not interfere with UFLS program in effect. Also on Attachment 1, this is now labeled "Off Nominal Frequency Capability Curve." SPCS suggests that the word "capability" in this label is potentially misleading. This is not a machine capability curve. There should be a statement that protective device settings should be based on machine damage considerations and should be arrived at in consultation with the machine manufacturer. The curve presents limits to those settings which are designed to prevent interference with UFLS programs. The SDT has not described how the curve was compiled. Technical committees within the IEEE went to great lengths to describe the turbine blading off-frequency limitation curves. Every manufacturer submitted their curve and a family of curves was created that showed distinct curves for each manufacturer. The NERC 1978 document, "Underfrequency and Undervoltage Relay Applications Large Turbine Generators included a collection of individual manufacturer which when plotted together provided a prospective on the widely varying limits of the various turbines. There is a danger of misinterpretation to use one curve. In PRC-024-1 there was no description stating how the curve was developed. If a machine is not at risk and if a UFLS simulation shows that the bottom frequency will occur outside of the "one size fits all curve" then there should be a provision to use the manufacturer's curve rather than shed more load just to fit the attachment 1 curve. A.R1 and A.R2 wording could be taken to require that such relaying should be enabled and set. The phrase "Installed … relaying not to trip during …" could be taken to mean that such relaying is assumed to be, or should be, installed. Also, in the case of generator multifunction protective devised, such relaying is always installed but it is not appropriate in many cases that it be enabled and set. Note this consideration applies to both frequency and Voltage. In general, this Standard should take care to point out that any protection application should be based on actual specific machine protective considerations which should be arrived at in consultation with the machine manufacturer. Concerning A.R1.2 and Attachment 1, the language refers to a “no trip zone" between curves, and obviously there is a permissible trip zone outside the curves. Questions will arise on permissibility of settings which are actually on the curves. SPCS would suggest that setting directly on the curves should be permitted. For example, if 1.0 seconds at 57.8 Hz is directly on the curve, failure to deal with this question will result in pointless and counterproductive settings such as 1.0 seconds at 57.79 Hz. SPCS suggests "Setting directly on the curves is permitted, and settings outside the curves are permitted." Concerning A.R2, this Standard addresses setting of Voltage relays based on Voltage at the point of interconnection, which is not directly translatable to Voltage at the generator terminals. The generator real and reactive power output will affect the relationship, and this is not dealt with in this Standard. Simply setting the generator protection relay at 0.90 per unit may, in fact, be an incorrect setting to achieve the desired performance. Settings must include allowances for all equipment tolerances: voltage transformer errors, relay tolerances, and testing instrumentation errors. The actual setting needed to account for such variances may require that the relay be actually set to trip at 0.84 or 0.86, or some other seemingly conflicting value, in order to achieve the goal of not tripping at 0.90 per unit.
Group
PJM Interconnection
Patrick Brown
PJM Interconnection
Yes
 
Yes
 
 
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
Yes
In R2.2.1, replace -greater- with -faster- or -slower-, whichever is correct. In R2.2.3 replace -intended- with -required-. In R4, replace -written- with -documented-. In R5, add an -s- to -System- in the parentheses. In R3, R4 and R5 - Concerned with the GO responsibility to send to their RC, PC, TO and TP. Would rather see the GO responsibility be to just to respond to any RC, PC, TO and TP requests.
Individual
Brent Ingebrigtson
E.ON U.S.
Yes
 
Yes
 
No
 
 
Yes
 
No
E.ON U.S. believes that the standard should apply to facilities at 200 kV and above in order to be consistent with equipment thresholds of other NERC standards.
Yes I agree with the approach
 
Yes
 
 
 
No
 
Group
Dominion
Jalal Babik
Dominion Resources Services, Inc.
Yes
 
Yes
 
 
 
Yes
 
Yes
 
No I disagree with the approach
All generators identified in a transmission owner's restoration plan warrant a high VRF. Additionally, generators ≥ 500 MVA warrant a high, generators > 100 MVA but < 500 MVA warrant a medium and generators ≤ 100 MVA warranty a low VRF
Yes
 
We are not aware of any. However, we are aware that a number of regions have draft UFLS standards that apply to generators despite the fact NERC Reliability Standards PRC-007, PRC-008 and PRC-009 do not contain either GO or GOP in the applicability section. These regional drafts contain provisions that require non-conforming generators to acquire 'load shed' service. We have repeatedly cited our inability to find any entity that would offer such service as well as technical difficulties in developing a UFLS predicted upon such a service. Despite our comments, the latest drafts continue to require non-conforming generators to acquire 'load shed' service.
Yes. We are aware of agreements between some generators and their respective transmission owners that contain frequency coordination requirements that differ from those in Table 1, and that, in some cases, the transmission facility(ies) that connects the generator to the BES has underfrequency tripping that would operate prior to the levels shown in Table 1, thus negating any modification that a generator might make to conform. We suggest that this standard also exempt these GOs from meeting R1 and R2 and that R5 be modified to allow for such exception.
Yes
We would like to commend the SDT for recognizing that there may be technical reasons that prevent a generator from meeting requirements 1 and 2 and allowing an exemption when technical basis is provided (R5). There is a paragraph on the second page which states that " For voltage excursions, only generator under or over voltage protective relays and volts per hertz relays would need to be evaluated to meet the draft requirements. Steady state evaluations only are expected " We have the following questions: (1) Do the relays mentioned in the statement above include auxiliary system under voltage relays? It appears the voltage relay part of the standard is limited to only relays that directly trip the generator and not relays that trip auxiliaries. Is that the intent? What if the relay was attached to an auxiliary bus, but tripped the generator? (2) How is that only steady state evaluations are enough? How do you study voltage recovery characteristics without dynamic simulations? If the standard is intended to apply to volts per hertz relays, suggest: 1. Revising footnote 1 to specifically include volts per hertz relays. 2. Revise Steps 4.2.1 and 4.2.2 to specifically include volts per hertz relays. 3. That the standard should incorporate specific guidance for facilities using volts per hertz logics and include a graph showing the voltage and frequency excursions in terms of volts per hertz.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Both bullets should be checked above (form will not accept). The responses received were divided, and below are the comments received for your consideration. The Generator Operators, and not the Generator Owners, are typically responsible for establishing relay setpoints, calibrations, and maintenance. The Generator Owner is the Functional Model entity that has direct control over the generating unit protection settings.
No
Both bullets should be checked above (form will not accept). The proposed standard addresses all issues identified in the Standard Authorization Request. Coordination of generator and transmission system protection is addressed in PRC-001. As presently constituted this Standard will likey result in the inappropriate enabling and setting of frequency and voltage relays with the settings which are permitted, thus reducing system reliability, which is contrary to its stated purpose. This is supported in the comments provided below. There are significant machine protection issues which are not addressed, such as Volts per Hertz. Loss of generation consequential to problems on auxiliary systems, problems which arise due to low voltage or low frequency, or a combination of both, is a significant problem, and is not addressed in this Standard.
Yes
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
No
Both bullets should be checked above (form will not accept). The curves should be revised based on generator capabilities and design requirements rather than the expected system response for simulated disturbances. Although the simulation results and tools used to develop the curves have not been provided it appears that the proposed curves are based on transient stability simulations. The transient stability program includes only the positive sequence component of system voltage and neglects phenomena that do not result in significant shaft torques. By contrast, protective relays measure individual phase or phase-to-phase quantities or in some cases specific sequence quantities. As proposed the curves may be interpreted differently in relay applications to the detriment of bulk electric system reliability and customer service. Since the curves will be used to set protective relays they should be based on the quantities that are measured by protective relays and the quantities should be clearly stated. We have provided examples of how the curves could be misinterpreted or misapplied if the curves are not constructed in terms of measured relay quantities and settings specific to the point of measurement: • Based on the proposed curve an overvoltage relay can be set at 120% with no intentional time delay. If this relay measures phase-to-ground voltage at the Point of Interconnection (POI) then for a close-in line-to-ground fault the unfaulted phases may have fundamental frequency voltages of 125% or more for the duration of the fault (effectively grounded system), resulting in undesired generator tripping prior to clearing the fault from the transmission system. • Protection against overvoltages that are shorter in duration than the operating time of circuit breaker is provided by surge arresters on the high-voltage terminals of the transformer and by surge protectors on the terminals of the generator. The curve implies that for a voltage of more than 120% that the generator can trip instantaneously (without intentional time delay). We suggest that instantaneous trips at any voltage level are neither required nor effective for generator protection. The overvoltage curve should approach zero time asymptotically or alternatively 250% for 20ms, 135% for 300ms, 120% for 20 seconds, 110% continuously. Alternatively the curve should be based on generator capability rather than FERC 661A which is applicable to wind generators with very limited capability. • In the undervoltage region the 9 cycle zero voltage has been carried over from FERC 661-A which is to facilitate wind integration. The 9 cycle zero voltage ride-thru, although less than prior utility designs, may be sufficient. We again recommend that SDT translate the intended positive sequence values to phase quantities measured by the relay to avoid misapplication. A single-line-to-ground fault will result in a positive sequence voltage of approximately 0.5-0.7pu but the voltages on individual phases or between phases may be quite different. The curve appears adequate from a positive sequence perspective but may not be interpreted as intended. • In the undervoltage region we recommend that 85% be applied from 3 seconds to 15 seconds to ensure that generators stay connected longer than load and to permit time for automatic reactive element switching. There is no reason to trip this fast in this region Based on the proposed curves we are concerned that the SDT has considered only the system response to typical design contingencies and only the positive sequence voltage from transient stability simulations. Although we have suggested alternate values the final values will depend on how the curve is defined, the form of measurement and relay application. As proposed we believe the curves leave too much for misinterpretation and misapplication. We respectfully question whether it is conceptually possible to properly state this criteria as a single curve. There are a number of important issues that arise with this approach, including the following: > In general generators should not trip on UV, but should alarm. Please see latest C50.12 and C50.13. UV is generally a thermal consideration and an alarm is appropriate to call operator attention to a malfunction. > The existence of a curve such as this in a NERC Standard will lead to generators enabling UV and setting per some part of the curve, which could be a serious hazard to system reliability. > For some specific situations such as unmanned hydro units, tripping on time-UV is appropriate. > The idea of a ride-through curve originated with wind farms, and is not generally conceptually appropriate. For example, this approach is not conceptually appropriate for cylindrical rotor synchronous machines. > The minimum voltage for 9 cycles does not allow enough time to allow for breaker failure protection operation. 13 -15 cycles would be appropriate. > The voltages presented are at the point of interconnection and are not directly translatable to machine relay Voltage settings. > Machine Volts per Hertz curves are a significant issue and are not addressed. > The UV performance of plant auxiliaries is a significant issue, and is not addressed. > We suggest that ANSI/IEEE Standards C37.102, C50.12, and C50.13 should be used and listed as references to this Standard.
No
Both bullets should bec checked above (form will not accept). Reliability of underfrequency load shedding (UFLS) programs is dependent on assurance that the UFLS program will shed load prior to generation tripping in islanded conditions. The frequency response to generator tripping is primarily a function of the amount of generation tripped and is substantially independent of the location of the generator interconnection. Therefore, the standard should not specify a threshold on interconnection voltage. We are concerned that the generator unit capacity thresholds are set too high. Given the tolerances in UFLS program design, the unit capacity thresholds should be established to ensure that 99 percent of the generation in a system complies with the requirements of this standard. The SDT should identify unit capacity thresholds on this basis, similar to how thresholds were developed in MOD-026. The interconnection voltage is not relevant, only the amount of generation potentially lost to the system. Some sub-regions, employing a UFLS Program, are dependent on Generator Owners/Operators meeting the specifications for generator Underfrequency setpoints in order to maintain a viable UFLS Program. For sub-regions where a large percentage of the total generation fleet is comprised of individual units < 20 MVA and connected to buses < 100 kV, the contribution of these units to the overall success of the sub-regions UFLS Program are more pronounced. It is suggested that the threshold should be established by refering to the requirements of the Region or as established by the Reliability Coordinator (sub-region). As an alternative, it is suggested that all generating units operating in a Reliability Coordinators' or RTO/ISO's market system, regardless of size, shall follow this Standard based on their materiality to the reliability of the bulk power system.
No I disagree with the approach
Both bullets should be checked above (form will not accept).
No
Both bullets should be checked above (form will not accept). Given the potential impact on survivability of an island, and the need to lower the unit capacity thresholds for which this standard is applicable, as recommended in the comment to Question 5, it is suggested that the folowing Violation Risk Factor thresholds be applied: High > 100 MVA Medium > 20 MVA and < 100 MVA Lower < 20 MVA Given the potential impact on survivability of an island, and the recommendation in our response to Question 5 to lower the unit capacity thresholds for which this standard is applicable, we recommend the following Violation Risk Factor thresholds: High >100 MVA Medium > 20 MVA and ≤ 100 MVA Lower ≤ 20 MVA
We are aware that a number of regions have draft UFLS standards that apply to generators despite the fact NERC Reliability Standards PRC-007, PRC-008 and PRC-009 do not contain either GO or GOP in the applicability section. These regional drafts contain provisions that require non-conforming generators to acquire 'load shed' service. We have repeatedly cited our inability to find any entity that would offer such service as well as technical difficulties in developing a UFLS predicated upon such a service. Despite our comments, the latest drafts continue to require non-conforming generators to acquire 'load shed' service. The Quebec Interconnection, within the Eastern Interconnection, would need different settings from the ones listed in Attachment 1 to coordinate with its UFLS program.
Yes. We are aware of agreements between some generators and their respective transmission owners that contain frequency coordination requirements that differ from those in Table 1, and that, in some cases, the transmission facility(ies) that connects the generator to the BES has underfrequency tripping that would operate prior to the levels shown in Table 1, thus negating any modification that a generator might make to conform. We suggest that this standard also exempt these GOs from meeting R1 and R2 and that R5 be modified to allow for such exception.
Yes
Referencing R5 and R6 of the Standard: The Reliability Coordinator should be give veto power over exceptions to the requirements herein. Should the Generator Owner/Operator not be able to, or be unwilling to, make changes to setpoints to come into compliance with this Standard, the Reliability Coordinator should be given the authority to invoke required mitigation, such as requiring the Generator Owner/Operator to contract for compensatory load shedding up to the total amount of MW of each generating unit that fails to comply with the required setpoints. In addition, The "Off-Nominal Frequency Capability Curve" in Attachment 1 does not coordinate with the underfrequency load shedding (UFLS) program design parameters proposed by the NERC Underfrequency Load Shedding Standard Drafting Team for Project 2007-01. The misccoordination occurs in the time range approximatley between 5 and 10 seconds. This miscoordination can be eliminated by extending the horizontal line at 57.8 Hz to 5 seconds and revising the diagonal line to have endpoints at 57.8 Hz/5s and 59.5 Hz/1800s. This modification will provide coordination with the UFLS program design parameters while still maintaining coordination with turbine-generator capability. Due to the time scale on the graph in Attachment 2, the curves do not indicate the time at which the transient overvoltage and undervoltage requirements end, at which point the continuous voltage requirements would be applicable. Here are several other points that have come up regarding other parts of PRC-024-1 that were not covered above: > Concerning Attachment 1, we believe this is mainly present to infer that generator tripping will not interfere with UFLS programs. There should be a statement that settings should not interfere with UFLS program in effect. Also on Attachment 1, this is now labeled "Off Nominal Frequency Capability Curve." We wish to suggest that the word "capability" in this label is potentially misleading. This is not a machine capability curve. There should be a statement that protective device settings should be based on machine damage considerations and should be arrived at in consultation with the machine manufacturer. The curve presents limits to those settings which are designed to prevent interference with UFLS programs, and the curve should be so labeled. > A.R1 and A.R2 wording could be taken to require that such relaying should be enabled and set. The phrase "Installed … relaying not to trip during …" could be taken to mean that such relaying is assumed to be, or should be, installed. Also, in the case of generator multifunction protective devised, such relaying is always installed but it is not appropriate in many cases that it be enabled and set. Note this consideration applies to both frequency and voltage. In general, this Standard should take care to point out that any protection application should be based on actual specific machine protective considerations which should be arrived at in consultation with the machine manufacturer. > Concerning A.R1.2 and Attachment 1, the language refers to a 'no trip zone" between curves, and obviously there is a permissible trip zone outside the curves. Questions will arise on permissibility of settings which are actually on the curves. We would suggest that setting directly on the curves should be permitted. For example, if 1.0 s. at 57.8 Hz is directly on the curve, failure to deal with this question will result in pointless and counterproductive settings such as 1.0 s. at 57.79 Hz. We suggest "Setting directly on the curves are permitted, and settings outside the curves are permitted." > Concerning A.R2, this Standard addresses setting of voltage relays based on voltage at the point of interconnection, which is not directly translatable to voltage at the generator terminals. The generator real and reactive power output will affect the relationship, and this is not dealt with in this Standard. We would like to commend the SDT for recognizing that there may be technical reasons that prevent a generator from meeting requirements 1 and 2 and allowing an exemption when technical basis is provided (R5). There is a paragraph on the second page which states that " For voltage excursions, only generator under or over voltage protective relays and volts per hertz relays would need to be evaluated to meet the draft requirements. Steady state evaluations only are expected " We have the following questions: (1) Do the relays mentioned in the statement above include auxiliary system undervoltage relays? It appears the voltage relay part of the standard is limited to only relays that directly trip the generator and not relays that trip auxiliaries. Is that the intent? What if the relay was attached to an auxiliary bus, but tripped the generator? (2) How is that only steady state evaluations are enough? How do you study voltage recovery characteristics without dynamic simulations?
Individual
Brendan Kirby
AWEA
Yes
 
Yes
PRC-024 should be a performance standard but since that is unlikely to pass I can live with a relay setting standard
No
 
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
No
 
Individual
Mark L Bennett
Gainesville Regional Utilities
No
In a number of smaller utilities, they are the same and do not need to be addressed separately
No
In some areas there is no reason to include generators less than 100 MVA
No
 
 
No
I am concerned that Generator Operators even understand what is written above
Yes
 
Yes I agree with the approach
 
No
I believe that > than 100 mva should only be included
 
 
 
Individual
Michael Goggin
American Wind Energy Association
Yes
 
Yes
A relay setting standard is fine, although the wind industry would also be able to comply with the standard if it were a performance standard.
No
 
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
No
 
Individual
Cleyton Tewksbury
Veolia Environmental Services
No
The generator operator is the entity charged with maintaining the facility. Therefore, the GOP has all the necessary records and procedures.
Yes
 
No
 
 
Yes
 
No
Additional criteria would be useful to identify units that are critical to the BES. If a BA and/or TOP has identified a unit a non-critical, then such a unit should be exempt from this standard regardless of size and connection voltage.
No I disagree with the approach
The delineation should be based on actual or potential impact to the BES of a unit tripping as determined by the BA and TOP modeling.
No
Size should not be a factor, only practical impact to the BES.
 
 
No
 
Individual
test
test
Yes
 
No
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No
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Yes
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No
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No I disagree with the approach
sdfsdfsd
Yes
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Individual
Mark Ringhasuen
Old Dominion Electric Cooperative
No
I agree that the Go is the primary function for this requirement, but given the multitude of Go/GOP configuations out there, I think the GOP function should also be included in the applicability secttion of this standard.
Yes
 
No
I am not 100% sure this is the case, but I am fairly confident all our units do meet these thresholds.
 
Yes
In general, I agree with your curve. I need to review more completely before I am ready to vote Yes on it.
Yes
This is the NERC/FREC set levels, all units with this scope should have to comply with the standard. Units that are not within the above criteria should be exempt from it as they are not aware, possible to provide their input.
No I disagree with the approach
I assume this was because the bigger units have a bigger impact on reliability than the smaller units. I am fine with this approach, but might have a minor comment on the break levels.
Yes
Might have a minor tweak in the future.
No.
No.
Yes
Provide some insight on Technical Exceptions for generators that cannot met these requirements (the CIP TFE process might be useful in this)
Individual
Patrick Farrell
Southern California Edison Company
No
The Generator Operator should be the functional entity to whom the standard applies because Generator Operators tend to change the settings without warning or permission.
Yes
 
Yes
Uncertain, as curves and tables in attachments need additional clarification.
Uncertain, as curves and tables in attachments need additional clarification.
No
Additional information is need for clarity on the curve and table in the attachment.
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
Yes
The curves and tables in the attachments require additional clarification.
Individual
Barry Francis
Basin Electric Power Cooperative
Yes
I have some problems with the intent of this standard in general, but a standard of this nature would have to apply to the generator owner.
No
Generation under frequency protection is an area I have spend much time on over the last 20 years, and I admit that I hold some strong opinions, but these opinions were arrived at after much study, disturbance analysis, and from being directly involved in actual design of three regional underfrequency load shedding (UFLS) programs. It appears that the generator off-nominal frequency protection limits shown in attachment 1 represent someone's judgment call of what is a reasonable loss of life per event, what the expected minimum frequency might be when load shedding occurs, and so forth. Such judgment calls are subjective, and there is room for interpretation. I feel that generation underfrequency/overfrequency settings of this nature have to be developed on a regional basis as part of a regional underfrequency load shedding program. I am uncomfortable with this showing up in a draft NERC standard without any supporting technical documentation or justification. I agree that unit capabilities have to be considered, but perhaps more important, we have to consider the realities of what we can achieve with UFLS and give ourselves enough generator tripping delay time and relay margin to make the program work. Tradeoff's are involved, and this type of underfrequency analysis is inherently an estimation, so some time delay margin is needed to ensure coordination with load shedding. If generation trips too soon, the island imbalance will increase and it may not be possible to prevent total collapse of the island. Keep in mind that the real off-nominal frequency loss of life exposure is when black start programs try to pick up the pieces after load shedding fails, and premature tripping of generation is what causes load shedding to fail. In addition, hydro systems can operate at much lower frequencies than steam units, and this criteria is not appropriate for hydro systems. In my opinion, UFLS is supposed to be a safety net to cover the unforeseen, and it needs to be designed with that in mind. Ideally, we want it to be as robust as possible. Relay coordination is going to be more robust when based on worst-case performance and not on best case. This helps deal with real world complications imposed by things we have not anticipated or foreseen, or due to "as implemented" programs always being a little different than the ideal stated in the design phase. My most recent involvement with UFLS and generator off-nominal frequency protection coordination came about through the MRO Underfrequency Load Shedding Task Force effort that developed a new coordinated UFLS program for the MRO footprint. I served as chair of this taskforce and did much of the analysis. I do not want PRC-024-1 to establish standards that conflict with the MRO program. Doing so would sacrifice the effectiveness of the load shedding program we came up with. There are a couple of other areas where conflicts occur. This is in regards to how to deal with programs that need to shed more than the minimum amount of load, and in regards to the overfrequency implications. I will discuss the issues in sequence. Although the MRO UFLS Taskforce expects that under "typical conditions" that minimum frequency will be above 58 Hz, (for loss of generation/import of up to 30% of system load in the island), our worst case simulations indicate we could briefly dip below that, and we used our worst case results to set generation protection times and delays. In addition, our "equivalent inertia" modeling approach ignores machine to machine oscillations which might cause frequency at different locations to differ by .2 Hz or so as the system rings down. For this reason, we chose 57.6 Hz as the point where instant tripping is allowed. This is below our worst-case minimum frequency of 57.77 Hz (for a very low inertia, low damping, no governor scenario that is perhaps overly pessimistic). This can also be justified by considering that our design criteria set a target of average system frequency >= 58 Hz, which has to be adjusted by about - .2 Hz for machine to machine oscillations seen in the real system and not in our model, plus about .2 Hz margin to ensure good relay coordination). In order to come up with the MRO generation protection settings we monitored time spent in frequency bands spaced .1 Hz apart and we consider the performance over the full range of coverage (0 to 30 % loss of generation) and considered a wide range of assumptions concerning system based inertia (H system base = MW-sec stored in rotating mass divided by P gen) and damping in addition to a possible range of governor actions. We optimized the program to minimize time spent below 60 Hz while addressing all the other constraints we had to deal with. Once we knew the expected worst case times in each .1 Hz band below 60 Hz for the optimized program, we came up with the stair step type of generation time delay settings that gave a reasonable fit to the expected worst-case time versus frequency information (plus some margin) with the fewest frequency bands. The MRO UFLS effort tried to anticipate as much complication as possible, but we could not cover all of the inherent uncertainty involved. No one could. The main source of uncertainty we could not deal with is how potential overvoltage’s may increase load and decrease the effectiveness of the load shedding program. This gave us additional justification for using a "no net governor response" scenario for evaluating coordination between load shedding and generator protection (this voltage uncertainty is not the only reason for using a no governor assumption: basically units that are base loaded cannot respond to underfrequency, power/load controllers may override governor action, combustion turbine thermal limits will quickly override their governor action with power dropping off faster than the frequency decline, wind generation may drop off and would not have a governor anyway, and so forth; the bottom line is that we do not know what level of net governor type of action we can count on, and what little we get may be offset by increases in voltage). To fully understand what we did you will have to refer to the MRO UFLS report on the MRO website. The short version is that we ran 1000's of cases to arrive at our conclusions. What we came up with for generator underfrequency protection minimum time delays is what we need to ensure the load shedding has time to play out to restore frequency and to give some margin to ensure relay coordination. If we tighten up the generation protection time delays and raise the frequency setting for the instant trip point, then there is a narrower range of conditions for which the UFLS program would be expected to work as intended. Our safety net becomes less robust, we make things less secure. On the other hand, the MRO load shedding program is designed to be the first line of protection for the generators as it is designed to force frequency recovery even in the absence of governor action by having small blocks of load shed on delay to kick us back towards 60 Hz when recovery is too slow. Although there is a chance that frequency may be slow to recover as a worst case, most of the time it will recover much faster than the times we used for generation tripping coordination. The expected time spent below 60 Hz sort of takes on the form of a probability density function. This type of information gives a better idea of what units may be exposed to. Therefore, our approach was to coordinate generation off-nominal frequency protection to match the worst case, and then do everything possible to minimize underfrequency exposure to generators when designing the load shedding program. The recommendations of the MRO UFLS report should take precedence over what is being proposed in this document. In MRO, we recognize that the Canadian portion of MRO needs to shed more than 30% of connected load. The MRO UFLS report indicates that any program that needs to shed more than 30% of load will need to relax the MRO generator off nominal frequency time delay settings for generation and accept longer delays and lower minimum frequencies. This is an engineering reality. The Off-Nominal Frequency Capability Curve on Attachment 1 does not give this kind of flexibility. Alternately, some improvement on minimum frequency can be realized by designing a program that oversheds but then the program will be prone to overspeed problems. Programs can also start shedding at higher frequencies to improve the minimum frequency but then that creates other coordination problems with neighboring programs. This standard writing process should not replace engineering judgment. Utilities need flexibility so they can make the necessary compromises after all things are considered. Making adjustments to generation protection is most likely the best approach to ensure coordination with these larger load shedding programs. The diagram from PRC-024-1 may suggest to some folks that over frequency tripping is going to be needed or perhaps even encouraged. I do not know what the intent is, so I will just express my concerns up front. I have serious reservations about applying dedicated relays, of the type used for underfrequency protection, to trip units on overspeed. Extreme caution is needed. That is a good way to ensure total collapse of a power grid. Seriously, this could be catastrophic. Consider that plants already have internal overspeed controls. These are needed to deal with full load rejection. These controls are in addition to the normal governor, and are much more drastic. These emergency overspeed controls are not modeled in stability cases, but they exist, and will take drastic action to slow down units if frequency gets high so I feel confident that the units self protect and take care of themselves. I believe that overspeed protection should be left to these inherent controls, and that we should not put in additional relays to trip generation on overspeed unless this is done carefully and solely for the purpose of restoring load and generation within an island. Plant internal overspeed controls have to limit speed following full load rejection, but they will also react to partial load rejections that we get by islanding. If a plant loses all lines to it (i.e. full load rejection), then go ahead and allow these inherent controls to trip the unit on overspeed or do what ever is needed. NERC does not need a standard for that. The emergency overspeed controls that protect for full load rejection can also activate on an islanding condition where we have too much generation in an island. On steam units these controls kick in between 61 to 62 Hz (it varies with each unit so I have to generalize), so system frequency is unlikely to get much higher than 61.4 Hz to 62 Hz (most that I have seen activate around 61.2 to 61.4 Hz) no matter how large the initial imbalance. Once these controls activate frequency is no longer a measure of the imbalance between load and generation. The action taken to prevent overspeed involves things like closing all the steam valves on thermal units, so it is safe to say we cannot stay in this high frequency condition for too long before random unit trips start to occur due to any number of internal plant problems. Often times one plant dies first and rebalances things for other units. The random nature of what happens next complicates any planned unit tripping actions to correct the imbalance. If dedicated unit tripping on overspeed is to be done, it can only be done on a few selected units and only as a way to hammer the imbalance back to a smaller size that we can deal with. The worst of all worlds would be to apply overspeed tripping to all units like we do for underfrequency. That would ensure any island with an initial excess of generation is going to go black after we dump all the generation. If generation is tripped to correct overspeed in an island, it has to be done in small increments (about 1 to 1.5 % of remaining load) and trip times have to be staggered. This is something that has to be studied on a case-by-case basis. In summary, we do not believe that it is appropriate to be creating a standard like this to specify settings for underfrequency/overfrequency protection for all generation. The technical basis of these limits are not given, and these setting may not coordinate with existing or proposed underfrequency load shedding programs. Aggressive load shedding programs are quite likely to need to accept more time below 60 Hz to coordinate with underfrequency relaying and expected system frequency recovery times. Protection settings of this nature should be developed in conjunction with underfrequency load shedding programs so that appropriate trade offs can be considered. Such coordination is most effective at the regional or subregional basis where a specific load shedding program can be evaluated in detail. We must give sufficient time for load shedding to act even if it means we need to accept some additional potential loss of life to generation for some hypothetical underfrequency event.
No
It is unclear what limits apply to wind generation, but we believe our conventional generation can easily accommodate the settings defined by Attachment 1, even though we feel that such off-nominal protection settings should not be established in this standard and that such coordination should occur at the regional level were UFLS program details are worked out. I would like to offer some observations based on real life experience. Our experience is that some folks have a good technical understanding of generation capabilities and others do not. In many instances, folks do not know what actual capabilities are, and if the proposed settings conflict with existing settings then they will initially report that they cannot accommodate the recommendations (the status quo carries a lot of weight even when no one can find the original justification for existing settings). Generally, all the parties have to get together and work through things to create a higher level of awareness of the issues so we can eliminate misconceptions. The new non-utility generation owners do not have the same load serving obligations as traditional utilities and this gives them different incentives for how they want to set generation protection. In many instances, they want to trip too early, to the detriment of the grid.
 
No
This may be appropriate but I have not seen the supporting technical report so I cannot say that I agree.
No
This is likely to be something that has to be applied on a case by case basis, with consideration given to how many units we have that would not be covered by some sort of coordinated UFLS/generation protection settings. There is some latitude to make exceptions, but in the future, we may have many more units that fit this category, and then this becomes a big issue. Units which trip too soon will just impact the load shedding program unless a corresponding amount of load is shed at essentially the same time and more or less at that same location.
No I disagree with the approach
This may be appropriate but I have not seen the supporting technical report so I cannot say that I agree. This is likely to be something that has to be applied on a case-by-case basis, with consideration given to how many units would be excluded in some geographic area. There is some latitude to make exceptions, but in the future, we may have many more units that fit this category, and then this exclusion becomes a big issue.
No
see above comment
See the detailed answer provided to question 2. It covers the need for regional variance.
The proposed generation off-nominal frequency criteria conflicts with the MRO UFLS program, and will not work for programs that need to shed more than 30% of system load. Technically this is not a conflict with regulatory functions, rule order, tariff, rate schedule, legislative requirement or agreement; but it is a conflict with our efforts to design an appropriate load shedding program for the MRO region.
 
Individual
Tony Kroskey
Brazos Electric Power Cooperative
Yes
 
Yes
 
 
 
 
Yes
 
Yes I agree with the approach
 
 
 
 
 
Group
Constellation Power Generation & Constellation Nuclear
Scott Etnoyer
Constellation Power Generation
No
The Generator Operators, and not the Generator Owners, are typically responsible for establishing relay setpoints, calibrations, and maintenance. The Generator Owner is the Functional Model entity that has direct control over the generating unit protection settings.
No
The proposed standard addresses all issues identified in the Standard Authorization Request. Coordination of generator and transmission system protection is addressed in PRC-001. As presently constituted this Standard will likey result in the inappropriate enabling and setting of frequency and voltage relays with the settings which are permitted, thus reducing system reliability, which is contrary to its stated purpose. This is supported in the comments provided below. There are significant machine protection issues which are not addressed, such as Volts per Hertz. Loss of generation consequential to problems on auxiliary systems, problems which arise due to low voltage or low frequency, or a combination of both, is a significant problem, and is not addressed in this Standard.
Yes
A number of our units do not meet this requirement but it is not known which of these cases are, due to actual machine design limitations.
 
No
The curves should be revised based on generator capabilities and design requirements rather than the expected system response for simulated disturbances. Although the simulation results and tools used to develop the curves have not been provided it appears that the proposed curves are based on transient stability simulations. The transient stability program includes only the positive sequence component of system voltage and neglects phenomena that do not result in significant shaft torques. By contrast, protective relays measure individual phase or phase-to-phase quantities or in some cases specific sequence quantities. As proposed the curves may be interpreted differently in relay applications to the detriment of bulk electric system reliability and customer service. Since the curves will be used to set protective relays they should be based on the quantities that are measured by protective relays and the quantities should be clearly stated. We have provided examples of how the curves could be misinterpreted or misapplied if the curves are not constructed in terms of measured relay quantities and settings specific to the point of measurement: • Based on the proposed curve an overvoltage relay can be set at 120% with no intentional time delay. If this relay measures phase-to-ground voltage at the Point of Interconnection (POI) then for a close-in line-to-ground fault the unfaulted phases may have fundamental frequency voltages of 125% or more for the duration of the fault (effectively grounded system), resulting in undesired generator tripping prior to clearing the fault from the transmission system. • Protection against overvoltages that are shorter in duration than the operating time of circuit breaker is provided by surge arresters on the high-voltage terminals of the transformer and by surge protectors on the terminals of the generator. The curve implies that for a voltage of more than 120% that the generator can trip instantaneously (without intentional time delay). We suggest that instantaneous trips at any voltage level are neither required nor effective for generator protection. The overvoltage curve should approach zero time asymptotically or alternatively 250% for 20ms, 135% for 300ms, 120% for 20 seconds, 110% continuously. Alternatively the curve should be based on generator capability rather than FERC 661A which is applicable to wind generators with very limited capability. • In the undervoltage region the 9 cycle zero voltage has been carried over from FERC 661-A which is to facilitate wind integration. The 9 cycle zero voltage ride-thru, although less than prior utility designs, may be sufficient. We again recommend that SDT translate the intended positive sequence values to phase quantities measured by the relay to avoid misapplication. A single-line-to-ground fault will result in a positive sequence voltage of approximately 0.5-0.7pu but the voltages on individual phases or between phases may be quite different. The curve appears adequate from a positive sequence perspective but may not be interpreted as intended. • In the undervoltage region we recommend that 85% be applied from 3 seconds to 15 seconds to ensure that generators stay connected longer than load and to permit time for automatic reactive element switching. There is no reason to trip this fast in this region Based on the proposed curves we are concerned that the SDT has considered only the system response to typical design contingencies and only the positive sequence voltage from transient stability simulations. Although we have suggested alternate values the final values will depend on how the curve is defined, the form of measurement and relay application. As proposed we believe the curves leave too much for misinterpretation and misapplication. We respectfully question whether it is conceptually possible to properly state this criteria as a single curve. There are a number of important issues that arise with this approach, including the following: * In general generators should not trip on UV, but should alarm. Please see latest C50.12 and C50.13. UV is generally a thermal consideration and an alarm is appropriate to call operator attention to a malfunction. * The existence of a curve such as this in a NERC Standard will lead to generators enabling UV and setting per some part of the curve, which could be a serious hazard to system reliability. * For some specific situations such as unmanned hydro units, tripping on time-UV is appropriate. * The idea of a ride-through curve originated with wind farms, and is not generally conceptually appropriate. For example, this approach is not conceptually appropriate for cylindrical rotor synchronous machines. * The minimum voltage for 9 cycles does not allow enough time to allow for breaker failure protection operation. 13 -15 cycles would be appropriate. * The voltages presented are at the point of interconnection and are not directly translatable to machine relay Voltage settings. * Machine Volts per Hertz curves are a significant issue and are not addressed. * The UV performance of plant auxiliaries is a significant issue, and is not addressed. * We suggest that ANSI/IEEE Standards C37.102, C50.12, and C50.13 should be used and listed as references to this Standard.
No
Reliability of underfrequency load shedding (UFLS) programs is dependent on assurance that the UFLS program will shed load prior to generation tripping in islanded conditions. The frequency response to generator tripping is primarily a function of the amount of generation tripped and is substantially independent of the location of the generator interconnection. Therefore, the standard should not specify a threshold on interconnection voltage. We are concerned that the generator unit capacity thresholds are set too high. Given the tolerances in UFLS program design, the unit capacity thresholds should be established to ensure that 99 percent of the generation in a system complies with the requirements of this standard. The SDT should identify unit capacity thresholds on this basis, similar to how thresholds were developed in MOD-026.
No I disagree with the approach
 
No
 
We are not aware of any. However, we are aware that a number of regions have draft UFLS standards that apply to generators despite the fact NERC Reliability Standards PRC-007, PRC-008 and PRC-009 do not contain either GO or GOP in the applicability section. These regional drafts contain provisions that require non-conforming generators to acquire 'load shed' service. We have repeatedly cited our inability to find any entity that would offer such service as well as technical difficulties in developing a UFLS predicted upon such a service. Despite our comments, the latest drafts continue to require non-conforming generators to acquire 'load shed' service.
Yes. We are aware of agreements between some generators and their respective transmission owners that contain frequency coordination requirements that differ from those in Table 1, and that, in some cases, the transmission facility(ies) that connects the generator to the BES has underfrequency tripping that would operate prior to the levels shown in Table 1, thus negating any modification that a generator might make to conform. We suggest that this standard also exempt these GOs from meeting R1 and R2 and that R5 be modified to allow for such exception.
Yes
The 4 kV protection that includes underfrequency and under volthge relays trip the generator in some of our plants. The SDT needs to clarify whether this standard applies to such protection.
Individual
Harianto Suryo
Lakeland Electric
Yes
 
Yes
 
No
 
 
Yes
 
Yes
 
Yes I agree with the approach
The VRF levels should range from low to high based on unit size and how the unit size impacts BES.
Yes
 
No
No
No
 
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
 
Yes
 
No
 
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
none
none
No
 
Individual
D. Bryan Guy
Progress Energy, Inc.
Yes
Since the generator operator does not own the equipment addressed by the standard, he cannot change the settings without the owner's approval. The standard potentially requires changing the frequency and voltage relay trip settings. Since the generator owner owns the equipment, they also own the settings and should be the one held accountable for meeting the requirements of this standard.
No
The purpose of the standard, to ensure that generators ride through the proposed system transients, will not be accomplished by only looking at generator protective relays. PE is concerend that these same profiles for frequency and voltage (Attachment 1 and 2) could later become applicable to all plant equipment. The generating plants are not designed to ride thru/stay connected for these proposed profiles.
Yes
100% of Progress Energy nuclear units will not stay connected per the proposed Attachment 1 and 2 due to auxliary equipment protection. 70-80% of the combustion turbine units would trip during the frequency excursions proposed by NERC. To make sure that generation "ride through" is coordinated with conditions that could damage all types of generation facilities, Progress Energy recommends that the SDT consult with turbine manfacturers to develop the frequency profile. Frequency limitations are typically driven by turbine manfacture design. We also need to the mindful of the total cummulative off-frquency excursions limits laid down by the turbine manufacturers. For example, most large steam turbine vendors prohibit turbine operation below 58 hz in order to prevent the probable occurrence of turbine blade resonance (turbine blade failure). Our nuclear plant operators will immediately manually trip the turbines at 58 hz to prevent equipment damage. For combustion turbines under frequency limitations exist below 59 Hz while the maximum operating duration at 59.5 Hz is limited to 60 seconds. Of our five nuclear plants, all five would not be capable of riding through either the proposed frequency or voltage transitents due to manual turbine and automatic reactor protection settings. These settings are not generator protective relays but they will result in a complete loss of generation. Two Progress Energy nuclear plants will trip on reactor coolant pump undervoltage below 80% pu at 0.75 seconds and one will trip on underfrequency below 58.2 hz at 0.2 seconds.
Approximately 3,500 MW of nuclear generation for SERC and 900 MW for FRCC. Approximately 3500 MW CT generation in SERC and 5000 MW CT generation in FRCC.
No
PE is concerend that the proposed profile for voltage (Attachment 2) could later become applicable to all plant equipment. The generating plants are not designed to ride thru/stay connected for this proposed profile. 100% of our nuclear units will trip if subjected to the proposed voltage transient test. The trips would be due to reactor coolant pump undervoltage, reactor coolant pump power monitoring protection, and reactor protection system power supply undervoltage exceeding their respective time delays during the voltage excursion. Each nuclear plant has slightly different trips based on the reactor design and vintage.
Yes
All generator units with the given thresholds are registered in the NERC compliance registry. We consider that such units should adhere to the requirements in the standard. Each system reacts differently to the loss of different sizes of generators. This standard, which is applicable to every entity, should cover all such situations. Hence, the given thresholds, though restrictive, are adequate.
No I disagree with the approach
It is the aggregate impact of all an entity's units that matters. There should be only one VRF - HIGH. Consider the example where a plant consists of numerous medium (100-200 MVA) units with a common relay setting error. WECC have relatively small units, but potentially large impact when the whole plant is affected.
No
There should not be levels.
No. FRCC has suspended work on a regional version of PRC-024. The regional version will have to reviewed and compared to the NERC standard once developed.
Yes, if the standard is extended to other plant equipment NRC nuclear plant licenses will be in conflict.
Yes
1. Recommend deleting proposed R2.2.2. If not deleted the language needs to be clarified as follows: "meet a shorter voltage ride through" should be changed to "meet a less stringent voltage ride through". 2. In R3, change "within 30 calendar days of any change" to "at least 30 calendar days prior to any change". The changes should be provided before they are made in the field. 3. In M4, change "entities listed in Requirement 4" to "entities listed in Requirement 4 that provide a written request" 4. The purpose and the applicability of the standard needs to be revised to clearly specify that the scope of PRC-024-1 only applies to main generator protective relaying and excludes protective functions associated with plant auxilary equipment.
Group
SERC Dynamics Review Subcommittee (DRS)
Rick Foster
Ameren Services
Yes
Since the generator operator does not own the equipment addressed by the standard, he cannot change the settings without the generator owner's approval. The standard potentially requires changing the frequency and voltage relay trip settings. Since the generator owner owns the equipment, they also own the settings and should be the one held accountable for meeting the requirements of this standard.
No
Settings for generator backup impedance and voltage restrained overcurrent relays need to be covered too. Their inclusion will provide complete coverage of the generator. There have been instances where these relays have operated in the past. We understand that this will drive the need for dynamic simluations because steady state simulations will not suffice.
 
 
Yes
However, the wording used in section R2.2.1 is confusing. The words should be changed to "For three-phase transmission system zone 1 faults with Normal Clearing, generator relaying shall be set longer than the expected fault clearing time, but not greater than nine cycles."
Yes
All generating units with the given thresholds are registered in the NERC compliance registry. We believe that these units should adhere to the requirements in the Standard. Each system reacts differently to the loss of different sizes of generators. This Standard, which is applicable to every registered entity, should cover these situations. Hence, the given thresholds, though restrictive, are adequate.
No I disagree with the approach
It is the aggregate impact of all an entity's units that matters. There should be only one VRF - HIGH. Consider the example where a plant consists of numerous medium sized (100-200 MVA) units with a common relay setting error. Even though the individual units are relatively small, there is a potentially large impact when the whole plant is considered.
No
There should not be levels
 
 
Yes
1. We recommend deleting the proposed section R2.2.2. If not deleted, change: "meet a shorter voltage ride through" to "meet a less stringent voltage ride through". 2. In R3, change "within 30 calendar days of any change" to "at least 30 calendar days prior to any change". The changes should be provided before they are made in the field. 3. In M4, change "entities listed in Requirement 4" to "entities listed in Requirement 4 that provide a written request"
Individual
Bob Shanks
NIPSCo
Yes
 
Yes
 
Yes
4.7 % estimated percentage of units that can't meet thresholds due to design limitations:
155 Estimated total MW capacity of units that cannot meet the requirement.
Yes
 
 
Yes I agree with the approach
 
Yes
 
 
 
Yes
R4 These groups should already have this information. The coordinators or planners should have proof and be able to provide this information now. R5 Normally would not accumulate enough time in the under-frequency zone to be a danger to the turbine blades but under unusual circumstances might accumulate too much time and not be able to continue to operate in the under-frequency region that is being specified. We might not have enough time to wait for the 30 day period.
Group
Luminant Power
Rick Terrill
Generation Compliance
Yes
 
Yes
 
No
 
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
NA
NA
No
 
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
 
Yes
A performance standard would be virtually impossible to perform and verify for all the equipment at a plant. The relay approach may not meet the SAR objective for generators to remain on line through voltage and frequency excursions, but this approach is the only practical way that allows standard requirements to be written and enforced.
 
 
 
Yes
A single unit not meeting these thresholds (an unregistered unit) can always be registered if a technical justification is given and proven. However, this does not mean a "blanket" registration can apply to all units (unregistered units) that do not meet these thresholds.
Yes I agree with the approach
 
 
 
 
 
Individual
Rick White
Northeast Utilities
Yes
 
Yes
 
Information not available at this time.
Information not available at this time.
Yes
 
No
Significant generator capacity may be connected at distribution voltages and set with sensitive anti-islanding frequency/voltage setpoints. These generators need to report their setpoint data to the owner of any UFLS/UVLS systems that may be affected by the generator performance. This can be a significant amount of generation relative to the size of the UFLS/UVLS program. Consideration should also be given as to whether the requirements should apply to generators where the site aggregate is >20MVA.
Yes I agree with the approach
 
 
 
 
Yes
R2.2.1 seems to imply that a generator must set an undervoltage trip with a time delay of no more than 9 cycles. This seems to conflict with the intent of PRC-024. Is the intent perhaps to require the TO to clear Zone 1 faults in no more than 9 cycles? Or is the intent to allow the GO to set the time delay as low as 9 cycles and no less? I suggest the latter. R3, R4, and R5 - This information should be provided to the owner of any UFLS or UVLS as well.
Group
Southern Company
Hugh Francis
Southern Company Services
Yes
If the standard is in place, it belongs to the Generator Owner. The SAR seemed to be written for transmission, but this standard seems to be evolving to a geneator setting standard. Does the SAR need to be revised? Although GO has the access to the equipment settings/records, GOP may not, GOP is the entity to operate the units. GO must communicate settings to the GOP. Since the generator operator does not own the equipment addressed by the standard, he cannot change the settings without the generator owner's approval. The standard potentially requires changing the frequency and voltage relay trip settings. Since the generator owner owns the equipment, they also own the settings and should be the one held accountable for meeting the requirements of this standard.
No
What the standard addresses is probably what is practical, but the ultimate goal of the SAR is not practical to implement. We question whether the goal of this standard can be truly addressed from a practical standpoint. The scope of the protective equipment covered in the current draft excludes excitation system protection including over excitation, station service under voltage protection, certain nuclear facility protection schemes, boiler controls, turbine controls, each of which may not ride through the frequency and voltage swings. We feel as though the limited approach of specifying F and V relay settings on the generator may be futile in improving the ability to ride through – yet on the other hand the inclusion of all of the impacted plant subsystem components would be practically and financially unmanageable. In other words, will any appreciable improvement in system reliability result from the implementation of this standard looking at F and V gen settings only. Settings for generator backup impedance and voltage restrained overcurrent relays may need to be covered too. Their inclusion will provide complete coverage of the generator. There have been instances where these relays have operated in the past. We understand that this will drive the need for dynamic simluations because steady state simulations will not suffice.
Yes
Some are, some are not. Some we can prove, some we don't know and can't find out. With no experts to evaluate turbine under/over frequency in our company and turbine manufacturers either out of business or unwilling to provide turbine limits, is there any possible exception allowed for settings inside the no trip zone? Also, for existing turbines, we believe that the turbine blade conditions would have to be evaluated to make a judgement on how to shift the withstand. How can we be sure that we are not stressing our turbine if we set our devices outside of the curve in the standard? Can question 3 be addressed quantitatively? Instead of "100% on voltage", it should be "0%". Auxiliary systems are not included in the standards scope as drafted. 100% on voltage (can't prove - auxilliary system) Unknown on frequency
40,000MW voltage, Unknown frequency
No
Controversy of Voltage cumulative nature, not showing the 95%-100% generator terminal voltage, difference between the curve being on the tranmission side of the GSU and the generator relay being on the generator side of the GSU. The generator terminal voltage shown at 95%-105% listed in R2.1. We are concerned that future auditors will interpret this limit as being the coordination limit. The voltage curve of Attachment 2 is stated for system voltage; however as mentioned in the conference call, the volts per hertz protection was specifically referenced and used to support setting criteria. We have a problem with this approach since the V/HZ relay is looking at the generator voltage and the curve is shown for the system voltage. How do we demonstrate coordination since the two are on different basis which cannot accurately be resolved via steady state techniques? The wording used in section R2.2.1 is confusing. The words should be changed to "For three-phase transmission system zone 1 faults with Normal Clearing, generator relaying shall be set longer than the expected fault clearing time, but does not have to be set for greater than nine cycles."
No
The unit size and plant size seem to be conservatively small. From a practical standpoint, our focus in this standard should be on the largest units, those that are most cricital in the reliability. A more reasonable limit would be 100MVA generator units and 200 MVA for multiple units at a single site.
Yes I agree with the approach
 
No
The VRF levels should range from low to high based on size of unit. Low risk 100-200MVA. Medium risk 200-500 MVA. High risk >500MVA.
No.
Nuclear Plant Requirements may conflict.
Yes
1. We recommend deleting the proposed section R2.2.2. If not deleted, change "meet a shorter voltage ride through" to "meet a less stringent voltage ride through". 2. In R3, change "within 30 calendar days of any change" to "at least 30 calendar days prior to any change". The changes should be provided before they are made in the field. 3. In M4, change "entities listed in Requirement 4" to "entities listed in Requirement 4 that provide a written request" 4. How did the SDT translate the transient voltage excursion plot to the cumulative voltage curve? 5. The voltage ride through curve was said to be cumulative – this should be specified on the curve. 6. How can we prove that our static voltage curve coordinates with this cumulative curve? 7. Implementation schedule – we believe that the unit size should be considered, and that the most critical units should be worked on first. Completing 33% each year is too ambitious for those members that have > 300 units. 8. What regions are working on voltage ride through and Underfrequency (ufls and undefrequency tripping of generators)? 9. Should the PRC-024 SDT wait until the regions have completed their work? 10. Generator engineers do not see a relevence for a voltage ride-through for any generator other than wind.
Group
Kansas City Power & Light
Tim Hinken
Kansas City Power & Light
Yes
 
No
In many cases the exciter voltage regulator includes generator protective functions (for example, Basler DECS 300, DECS 400) such as Volts/Hertz, undervoltage, overvoltage, underfrequency that will also trip the Unit. These functions are usually set slightly above the trip settings of the equivalent generator protective relaying, but to not include them in this requirement would effectively nullify the stability effort sought by this requirement.
Yes
There are a number of generating units that currently have relay settings outside the proposed underfrequency and overfrequency relay settings. It is not known at this time if it is possible to adjust the settings within the proposed relay settings. 50%
1900 MW
No
R2 specifies that the generator may not operate on V/Hz evaluated at nominal frequency. Some generators have specific requirements to trip on V/Hz at 110%. This is in conflict with the upper boundry point of Attachment 2 for times greater than 1 second. We recommend to change this requirement so that it does not apply to V/Hz settings. It is not practical to set generator protective relays fed from generator potential transformers to meet the voltage requirement at the point of interconnect to the BES. We recommend that the voltage chart requirement be applicable to the voltage measured by the generator protective relays, not the voltage at the point of interconnect to the BES.
Yes
 
Yes I agree with the approach
 
No
What is the basis for the MVA levels proposed by the standard here?
Not aware of any regional differences.
Not aware of any conflicts.
Yes
Please consider including the Balancing Authority as an entitiy for the Geneator Owner to provide settings information in requirements R3 & R4 since the BA is an entity that has a direct relationship with the operational status of generating stations. R5: Do not agree with the bulleted item where increasing the capabilility of a generator by 10% is a reason for exemption expiration. As an example, turbine or boiler enhancements can result in greater effeciencies and resulting in an increase of generator capability with no change to the generator or its protection capabilities whatsoever. Recommend removal of this bulleted item. R5: The generator exciter voltage regulator contains protective relay settings such as Volts/Hertz, undervoltage, overvoltage, underfrequency that will also trip the Unit. Is the exciter voltage regulator considered to be part of the generator protective relay system? If so, would a limitation of the exciter voltage regulator be allowed as an exception to the standard or, since the protective system is excluded, would R5 mandate that the excitor voltage regulator be replaced to remove the exception? This issue should be clarified in R5.
Individual
Roger Champagne
Hydro-Québec TransÉnergie (HQT)
Yes
The Generator Owner is the Functional Model entity that has direct control over the generating unit protection settings.
No
The proposed standard addresses all issues identified in the Standard Authorization Request. Coordination of generator and transmission system protection is addressed in PRC-001. As presently constituted this Standard will likey result in the inappropriate enabling and setting of frequency and voltage relays with the settings which are permitted, thus reducing system reliability, which is contrary to its stated purpose. This is supported in the comments provided below. There are significant machine protection issues which are not addressed, such as Volts per Hertz. Loss of generation consequential to problems on auxiliary systems, problems which arise due to low voltage or low frequency, or a combination of both, is a significant problem, and is not addressed in this Standard.
Yes
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
No
The curves should be revised based on generator capabilities and design requirements rather than the expected system response for simulated disturbances. Although the simulation results and tools used to develop the curves have not been provided it appears that the proposed curves are based on transient stability simulations. The transient stability program includes only the positive sequence component of system voltage and neglects phenomena that do not result in significant shaft torques. By contrast, protective relays measure individual phase or phase-to-phase quantities or in some cases specific sequence quantities. As proposed the curves may be interpreted differently in relay applications to the detriment of bulk electric system reliability and customer service. Since the curves will be used to set protective relays they should be based on the quantities that are measured by protective relays and the quantities should be clearly stated. We have provided examples of how the curves could be misinterpreted or misapplied if the curves are not constructed in terms of measured relay quantities and settings specific to the point of measurement: • Based on the proposed curve an overvoltage relay can be set at 120% with no intentional time delay. If this relay measures phase-to-ground voltage at the Point of Interconnection (POI) then for a close-in line-to-ground fault the unfaulted phases may have fundamental frequency voltages of 125% or more for the duration of the fault (effectively grounded system), resulting in undesired generator tripping prior to clearing the fault from the transmission system. • Protection against overvoltages that are shorter in duration than the operating time of circuit breaker is provided by surge arresters on the high-voltage terminals of the transformer and by surge protectors on the terminals of the generator. The curve implies that for a voltage of more than 120% that the generator can trip instantaneously (without intentional time delay). We suggest that instantaneous trips at any voltage level are neither required nor effective for generator protection. The overvoltage curve should approach zero time asymptotically or alternatively 250% for 20ms, 135% for 300ms, 120% for 20 seconds, 110% continuously. Alternatively the curve should be based on generator capability rather than FERC 661A which is applicable to wind generators with very limited capability. • In the undervoltage region the 9 cycle zero voltage has been carried over from FERC 661-A which is to facilitate wind integration. The 9 cycle zero voltage ride-thru, although less than prior utility designs, may be sufficient. We again recommend that SDT translate the intended positive sequence values to phase quantities measured by the relay to avoid misapplication. A single-line-to-ground fault will result in a positive sequence voltage of approximately 0.5-0.7pu but the voltages on individual phases or between phases may be quite different. The curve appears adequate from a positive sequence perspective but may not be interpreted as intended. • In the undervoltage region we recommend that 85% be applied from 3 seconds to 15 seconds to ensure that generators stay connected longer than load and to permit time for automatic reactive element switching. There is no reason to trip this fast in this region Based on the proposed curves we are concerned that the SDT has considered only the system response to typical design contingencies and only the positive sequence voltage from transient stability simulations. Although we have suggested alternate values the final values will depend on how the curve is defined, the form of measurement and relay application. As proposed we believe the curves leave too much for misinterpretation and misapplication. We respectfully question whether it is conceptually possible to properly state this criteria as a single curve. There are a number of important issues that arise with this approach, including the following: > In general generators should not trip on UV, but should alarm. Please see latest C50.12 and C50.13. UV is generally a thermal consideration and an alarm is appropriate to call operator attention to a malfunction. > The existence of a curve such as this in a NERC Standard will lead to generators enabling UV and setting per some part of the curve, which could be a serious hazard to system reliability. > For some specific situations such as unmanned hydro units, tripping on time-UV is appropriate. > The idea of a ride-through curve originated with wind farms, and is not generally conceptually appropriate. For example, this approach is not conceptually appropriate for cylindrical rotor synchronous machines. > The minimum voltage for 9 cycles does not allow enough time to allow for breaker failure protection operation. 13 -15 cycles would be appropriate. > The voltages presented are at the point of interconnection and are not directly translatable to machine relay Voltage settings. > Machine Volts per Hertz curves are a significant issue and are not addressed. > The UV performance of plant auxiliaries is a significant issue, and is not addressed. > We suggest that ANSI/IEEE Standards C37.102, C50.12, and C50.13 should be used and listed as references to this Standard.
No
Reliability of underfrequency load shedding (UFLS) programs is dependent on assurance that the UFLS program will shed load prior to generation tripping in islanded conditions. The frequency response to generator tripping is primarily a function of the amount of generation tripped and is substantially independent of the location of the generator interconnection. Therefore, the standard should not specify a threshold on interconnection voltage. We are concerned that the generator unit capacity thresholds are set too high. Given the tolerances in UFLS program design, the unit capacity thresholds should be established to ensure that 99 percent of the generation in a system complies with the requirements of this standard. The SDT should identify unit capacity thresholds on this basis, similar to how thresholds were developed in MOD-026. The interconnection voltage is not relevant, only the amount of generation potentially lost to the system. Some sub-regions, employing a UFLS Program, are dependent on Generator Owners/Operators meeting the specifications for generator Underfrequency setpoints in order to maintain a viable UFLS Program. For sub-regions where a large percentage of the total generation fleet is comprised of individual units < 20 MVA and connected to buses < 100 kV, the contribution of these units to the overall success of the sub-regions UFLS Program are more pronounced. It is suggested that the threshold should be established by refering to the requirements of the Region or as established by the Reliability Coordinator (sub-region). As an alternative, it is suggested that all generating units operating in a Reliability Coordinators' or RTO/ISO's market system, regardless of size, shall follow this Standard based on their materiality to the reliability of the bulk power system.
No I disagree with the approach
Given the potential impact on survivability of an island, and the need to lower the unit capacity thresholds for which this standard is applicable, as recommended in the comment to Question 5, it is suggested that the folowing Violation Risk Factor thresholds be applied: High > 100 MVA Medium > 20 MVA and < 100 MVA Lower < 20 MVA Given the potential impact on survivability of an island, and the recommendation in our response to Question 5 to lower the unit capacity thresholds for which this standard is applicable, we recommend the following Violation Risk Factor thresholds: High >100 MVA Medium > 20 MVA and ≤ 100 MVA Lower ≤ 20 MVA
No
Given the potential impact on survivability of an island, and the need to lower the unit capacity thresholds for which this standard is applicable, as recommended in the comment to Question 5, it is suggested that the folowing Violation Risk Factor thresholds be applied: High > 100 MVA Medium > 20 MVA and < 100 MVA Lower < 20 MVA Given the potential impact on survivability of an island, and the recommendation in our response to Question 5 to lower the unit capacity thresholds for which this standard is applicable, we recommend the following Violation Risk Factor thresholds: High >100 MVA Medium > 20 MVA and ≤ 100 MVA Lower ≤ 20 MVA
Yes, the Québec Interconnection, within the Eastern Interconnection, would need different settings than the ones depicted in the Attachment 1 to coordinate with its UFLS program. We are also aware that a number of regions have draft UFLS standards that apply to generators despite the fact NERC Reliability Standards PRC-007, PRC-008 and PRC-009 do not contain either GO or GOP in the applicability section. These regional drafts contain provisions that require non-conforming generators to acquire 'load shed' service. We have repeatedly cited our inability to find any entity that would offer such service as well as technical difficulties in developing a UFLS predicted upon such a service. Despite our comments, the latest drafts continue to require non-conforming generators to acquire 'load shed' service.
Yes. We are aware of agreements between some generators and their respective transmission owners that contain frequency coordination requirements that differ from those in Table 1, and that, in some cases, the transmission facility(ies) that connects the generator to the BES has underfrequency tripping that would operate prior to the levels shown in Table 1, thus negating any modification that a generator might make to conform. We suggest that this standard also exempt these GOs from meeting R1 and R2 and that R5 be modified to allow for such exception.
Yes
Referencing R5 and R6 of the Standard: The Reliability Coordinator should be give veto power over exceptions to the requirements herein. Should the Generator Owner/Operator not be able to, or be unwilling to, make changes to setpoints to come into compliance with this Standard, the Reliability Coordinator should be given the authority to invoke required mitigation, such as requiring the Generator Owner/Operator to contract for compensatory load shedding up to the total amount of MW of each generating unit that fails to comply with the required setpoints. In addition, The "Off-Nominal Frequency Capability Curve" in Attachment 1 does not coordinate with the underfrequency load shedding (UFLS) program design parameters proposed by the NERC Underfrequency Load Shedding Standard Drafting Team for Project 2007-01. The misccoordination occurs in the time range approximatley between 5 and 10 seconds. This miscoordination can be eliminated by extending the horizontal line at 57.8 Hz to 5 seconds and revising the diagonal line to have endpoints at 57.8 Hz/5s and 59.5 Hz/1800s. This modification will provide coordination with the UFLS program design parameters while still maintaining coordination with turbine-generator capability. Due to the time scale on the graph in Attachment 2, the curves do not indicate the time at which the transient overvoltage and undervoltage requirements end, at which point the continuous voltage requirements would be applicable. Here are several other points that have come up regarding other parts of PRC-024-1 that were not covered above: > Concerning Attachment 1, we believe this is mainly present to infer that generator tripping will not interfere with UFLS programs. There should be a statement that settings should not interfere with UFLS program in effect. Also on Attachment 1, this is now labeled "Off Nominal Frequency Capability Curve." We wish to suggest that the word "capability" in this label is potentially misleading. This is not a machine capability curve. There should be a statement that protective device settings should be based on machine damage considerations and should be arrived at in consultation with the machine manufacturer. The curve presents limits to those settings which are designed to prevent interference with UFLS programs, and the curve should be so labeled. > A.R1 and A.R2 wording could be taken to require that such relaying should be enabled and set. The phrase "Installed … relaying not to trip during …" could be taken to mean that such relaying is assumed to be, or should be, installed. Also, in the case of generator multifunction protective devised, such relaying is always installed but it is not appropriate in many cases that it be enabled and set. Note this consideration applies to both frequency and voltage. In general, this Standard should take care to point out that any protection application should be based on actual specific machine protective considerations which should be arrived at in consultation with the machine manufacturer. > Concerning A.R1.2 and Attachment 1, the language refers to a 'no trip zone" between curves, and obviously there is a permissible trip zone outside the curves. Questions will arise on permissibility of settings which are actually on the curves. We would suggest that setting directly on the curves should be permitted. For example, if 1.0 s. at 57.8 Hz is directly on the curve, failure to deal with this question will result in pointless and counterproductive settings such as 1.0 s. at 57.79 Hz. We suggest "Setting directly on the curves are permitted, and settings outside the curves are permitted." > Concerning A.R2, this Standard addresses setting of voltage relays based on voltage at the point of interconnection, which is not directly translatable to voltage at the generator terminals. The generator real and reactive power output will affect the relationship, and this is not dealt with in this Standard. We would like to commend the SDT for recognizing that there may be technical reasons that prevent a generator from meeting requirements 1 and 2 and allowing an exemption when technical basis is provided (R5). There is a paragraph on the second page which states that " For voltage excursions, only generator under or over voltage protective relays and volts per hertz relays would need to be evaluated to meet the draft requirements. Steady state evaluations only are expected " We have the following questions: (1) Do the relays mentioned in the statement above include auxiliary system undervoltage relays? It appears the voltage relay part of the standard is limited to only relays that directly trip the generator and not relays that trip auxiliaries. Is that the intent? What if the relay was attached to an auxiliary bus, but tripped the generator? (2) How is that only steady state evaluations are enough? How do you study voltage recovery characteristics without dynamic simulations?
Group
MRO NERC Standards Review Subcommittee
Michael Brytowski
MRO
Yes
 
Yes
 
No
The MRO does not own any generation.
 
Yes
Where would be the appropriate voltage measurement point? (Generator bus or POI)
Yes
 
Yes I agree with the approach
 
Yes
 
If a region has performed a detailed system study of the Under Frequency protection systems in their region and developed protective settings based off the characteristics developed in the study, the region should be allowed to deviate from the Generator Protection curve in Attachment 1.
No known conflict at this time.
Yes
It would be good to have the option of measuring the voltage at the Generator bus or POI. With the understanding that the voltage must be maintained of the POI.
Individual
Mark Thompson
AESO
 
 
 
 
 
 
 
 
 
 
Yes
In addition to the SRC ISO/RTO comments the AESO would like to add: As we understand it, the intent of this standard is to ensure that the generators ride through certain levels of frequency and voltage excursions, yet it only addresses the generator protection. We feel it must also address the protection and capabilities of the auxilliaries, unit transformers, lines, etc. If any of these trip off due to the same excursions that the generator is required to ride through, then the generator will be down and the standard will not have achieved its goal.
Individual
James H. Sorrels, Jr.
American Electric Power
Yes
 
Yes
It is appropriate to limit the scope of this standard to setting of voltage and frequency generator protective relays, but it should be noted that other factors may cause generators to trip as a consequence of voltage or frequency excursions besides voltage or frequency sensing relays. An example is tripping due to complications involving over-excitation protection. Are other factors addressed elsewhere?
No
 
 
Yes
 
Yes
The applicability appears to be from the NERC Compliance registry. This is probably okay for the requirement on voltage related tripping, but the impact of frequency related tripping is not restricted to the BES as it likely would be with voltage tripping. A separate single-size applicability, independent of BES/non-BES connection, may be more appropriate for the frequency tripping requirement.
Yes I agree with the approach
 
No
The MVA levels appear to be arbitrary. What is the basis that the SDT used to establish these MVA thresholds?
No known regional variances
No known conflicts
No
 
Individual
Greg Rowland
Duke Energy
Yes
 
No
Footnote 1 is unclear and too broad. As stated, it includes voltage regulators - which is beyond the scope of this standard. Take voltage regulator out, or specify the volts per hertz protection function only.
Yes
15% of system capacity
Approximately 4000 MW
Yes
The applicability of the curve is limited to the protective relays addressed by the standard. This curve is not meaningful if the plants were going to trip due to other causes. See our response to Question #9.
Yes
 
No I disagree with the approach
It is the aggregate impact of all an entity's units that matters. There should be only one VRF - HIGH.
No
It is the aggregate impact of all an entity's units that matters. There should be only one VRF - HIGH.
None
None
Yes
The issue typically addressed by international grid codes is an over-all plant performance standard and plant dynamic studies are perfomed to evaluate the impact on in-plant systems. Standards applicable to only generator protection might give a false sense that a plant could survive the transients and the reliability of the BES would be just as adversely impacted if large plants were to trip for causes other than a main generator relay. The basis and reliability benefit for voltage ride through transients should be clarified. Generator UF relays must coordinate with grid UFLS relaying. Some areas may apply UVLS and logic dictates that the coordination of that protection with a generator ride through criteria should be specified. Recommend that the scope of "equipment" that can be granted an exception be limited in some way or explicitly qualified. Otherwise, plant performance can be dictated by less-consequential auxiliary equipment (e.g. variable speed drives with UV settings per manufacturer standard instructions). Because R5 grants exception automatically in response to the GO providing documentation of any limitation. R5 bullet 2 - recommend changing "generator nameplate capacity rating" to "generator gross Real Power capability". The existing words are too general and including 'nameplate' is confusing.
Individual
Gregory Campoli
New York Independent System Operator
Yes
 
No
As presently constituted this Standard could result in the inappropriate enabling and setting of frequency and Voltage relays with the settings which are permitted, thus reducing system reliability, which is contrary to it's stated purpose. This is supported in the comments provided below. It would have been much more important to require that Voltage and frequency relays be applied only when they are required for machine protection, which this Standard does not do. There are significant machine protection issues which are not addressed, such as Volts per Hertz. Loss of generation consequential to problems on auxiliary systems, problems which arise due to low Voltage or low frequency, or a combination of both, is a significant problem, and is not addressed in this Standard.
Yes
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
A relatively small percentage of units do not meet this requirement but it is not known which of these cases are due to actual machine design limitations.
No
We respectfully question whether it is conceptually possible to properly state this criteria as a single curve. There are a number of important issues that arise with this approach, including the following: > In general generators should not trip on UV, but should alarm. Please see latest C50.12 and C50.13. UV is generally a thermal consideration and an alarm is appropriate to call operator attention to a situation or malfunction which results in low voltage. > The existence of a curve such as this in a NERC Standard will lead to some generator owners enabling UV and setting per some part of the curve, which could be a serious hazard to system reliability. > For some specific situations such as unmanned hydro units, tripping on time-UV is appropriate. > The idea of a ride-through curve originated with wind farms, and is not generally conceptually appropriate. For example, this approach is not conceptually appropriate for cylindrical rotor synchronous machines. > The minimum Voltage for 9 cycles does not allow enough time for breaker failure protection operation. 13 -15 cycles would be appropriate. > The Voltages presented are at the point of interconnection and are not directly translatable to machine relay Voltage settings. > Machine Volts per Hertz curves are a significant issue and are not addressed. > The UV performance of plant auxiliaries is a significant issue, and is not addressed. > We suggest that ANSI/IEEE Standards C37.102, C50 12, and C50.13 should be used and listed as references to this Standard.
No
The interconnection Voltage is not relevant, only the amount of generation potentially lost to the system.
Yes I agree with the approach
 
Yes
 
 
 
Yes
Here are several other points that have come up regarding other parts of PRC-024-1 that were not covered above: > Concerning Attachment 1, we believe this is mainly present to insure that generator tripping will not interfere with UFLS programs. There should be a statement that settings should not interfere with UFLS program in effect. Also on Attachment 1, this is now labeled "Off Nominal Frequency Capability Curve." We wish to suggest that the word "capability" in this label is potentially misleading. This is not a machine capability curve. There should be a statement that protective device settings should be based on machine damage considerations and should be arrived at in consultation with the machine manufacturer. The curve presents limits to those settings which are designed to prevent interference with UFLS programs, and the curve should be so labeled. > A.R1 and A.R2 wording could be taken to require that such relaying should be enabled and set. The phrase "Installed … relaying not to trip during …" could be taken to mean that such relaying is assumed to be, or should be, installed. Also, in the case of generator multifunction protective device, such relaying is always installed but it is not appropriate in many cases that it be enabled and set. Note this consideration applies to both frequency and Voltage. In general, this Standard should take care to point out that any protection application should be based on actual specific machine protective considerations which should be arrived at in consultation with the machine manufacturer. > Concerning A.R1.2 and Attachment 1, the language refers to a 'no trip zone" between curves, and obviously there is a permissible trip zone outside the curves. Questions will arise on permissibility of settings which are actually on the curves. We would suggest that setting directly on the curves should be permitted. For example, if 1.0 s. at 57.8 Hz is directly on the curve, failure to deal with this questions will result in pointless and counterproductive settings such as 1.0 s. at 57.79 Hz. We suggest "Setting directly on the curves are permitted, and settings outside the curves are permitted." > Concerning A.R2, this Standard addresses setting of Voltage relays based on Voltage at the point of interconnection, which is not directly translatable to Voltage at the generator terminals. The generator real and reactive power output will affect the relationship, and this is not dealt with in this Standard.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
 
Yes
However, it should clearer in the requirements how mechanical and electrical overspeed protection is coordinated with the UF relay settings. Also, we would appreciate the SDT's view on why the frequency requirement are not being written into the existing PRC-006 (UFLS) standard.
No
A possible concern would be the effect on auxiliary system equipment and reliability at voltages below 90%.
 
Yes
 
Yes
 
Yes I agree with the approach
A suggestion for SDT's consideration is that VRFs could be based on percentage of units not in compliance. A utility may have several large units (high VRF) and many small (low VRF) not in compliance.
Yes
 
 
This standard may need to be coordinated with current efforts to revise standard PRC-006-1, and with the Regional standards being developed for UFLS, such as RFC's PRC-006-RFC-01.
Yes
1. FE's consensus is that the PRC-024 allowable under-frequency vs. time tripping curve is too tight. By too tight, we mean that the LP turbine buckets and blades are much more tolerant of off freq operation than the proposed tables. Comparing them to the old ECAR curves and allowable tripping times shows they are more stringent. Given how seldom these events occur, (never happened yet in the Eastern Interconnect) expending more of this capacity appears justified. 2. Section A5 Implementation schedule - it may not give sufficient time to implement these requirements. We suggest an additional year as follows: no less than 33% within 2 years of effective date no less than 66% within 3 years of effective date no less than 100% within 4 years of effective date 3. R1.2 Should say off-nominal not off-normal. 4. R2.1 Suggest changing the word "measured" to "experienced". 5. In R5, we suggest changing the first bullet to read: "The equipment causing the limitation is modified, upgraded or replaced with equipment that removes the technical limitation.", and then delete the second bullet. 6. Requirements 3, 4 and 6 specify that the Generator Owner shall provide information to RCs, PCs, TOPs, and TPs that monitor or model the associated unit; however, there is no requirement for these entities to identify themselves to the Generator Owner. How will the Generator Owner know they have identified all of the entities that need the information? 7. In R5, the Generator Owner is granted an exception from requirements R1 or R2 simply by providing documentation of a equipment limitations. There is no independent view of the appropriateness of this exception. The drafting team should consider requiring independent verification of the equipment limitation prior to the granting of an exception to the requirements of the standard. 8. Sec. D References - Is this intended to be part of the standard? If so, it would be helpful if it was linked to the white paper so that we can review it. 9. In Requirements R3 through R6, the SDT may want to consider adding the Transmission Owner as nother entity who may need this information. 10. R2.2.1 may need to be re-worded as it requires that protection trip in no greater than 9 cycles. We are not aware of a disadvantage to the system if the tripping takes longer than 9 cycles.
Individual
Alice Murdock
Xcel Energy
No
We feel the GO would only be applicable for R6 and for when a new unit is being built. Once a unit is online, it is the GOP that would be performing all the actions to ensure compliance with R1-R5 of this standard. We also forsee compliance issues with jointly-owned units, if applicability were to remain only with the GO.
Yes
 
 
 
 
 
 
 
 
 
Yes
Please clarify if there is an expectation/requirement for new units to install voltage and frequency protective relays.
Individual
Armin Klusman
CenterPoint Energy
 
No
a) CenterPoint Energy does not agree with limiting the application of this standard to the few relays that the SDT has chosen to address (only generator under or over voltage protective relays and volts per hertz relays). In effect, the SDT is allowing possible tripping of generation during off nominal frequency and voltage excursions from several other types of relays and control systems. This may not provide adequate reliability, as loss of significant generation can occur for voltage sags. b) The SDT has not included generator backup over current, impedance, and loss of field relays within the scope of this draft standard. CenterPoint Energy believes these additional relays should also be addressed. CenterPoint Energy believes it is illogical to have a transmission relay loadability standard (PRC-023 ‘Transmission Relay Loadability’) based on current and impedance ride-through while exempting generators from comparable requirements. Such an exemption defeats the purpose of the transmission relay loadability requirements by allowing a system event to escalate due to failure of generator relays to ride-through the same types of events envisioned by PRC-023 requirements. One key purpose for PRC-023 is to “not interfere with system operators’ ability to take remedial action to protect system reliability.” c) In addition to including other types of generator relays, the relaying and control for plant auxiliary systems should also be addressed for operation during off nominal frequency and voltage excursions. Again, it is illogical to have a transmission relay loadability requirements based on current and impedance ride-through while exempting a generation plant from comparable requirements. CenterPoint Energy realizes that generating plants have many internal control systems on auxiliary equipment that could be impacted during low voltage events, but exempting such systems from this standard defeats its purpose. CenterPoint Energy also recognizes that failures or incorrect operation of equipment installed for voltage ride-through capability on auxiliary equipment controls, such as UPS devices, will occur. Therefore, CenterPoint Energy recommends the SDT specifically address plant auxiliary equipment ride through. CenterPoint Energy suggests that the requirements be similar to those in NERC standard PRC-004 ‘Analysis and Mitigation of Transmission and Generation Protection System Misoperations’. That is, if the plant incorrectly trips during a voltage sag due to auxiliary systems problems, the problem will be investigated and, where necessary, a system-wide corrective action plan will be developed and completed.
 
 
No
a) Attachment 2 of PRC-024-2 is truncated at 4 seconds and does not define the duration of the 0.9 pu voltage level. CenterPoint Energy recommends the total duration of the 0.9 pu voltage level be established at a MINIMUM of 10 seconds. The basis for 10 seconds is for coordination with undervoltage load shedding (UVLS) systems. b) Attachment 2 has a step function profile. CenterPoint Energy has reviewed these proposed steps for voltage recovery to 0.9 pu and concurs with most proposed steps. However, CenterPoint Energy studies indicate an insufficient coordination margin at the proposed 0.30 seconds at 0.65 pu voltage point. Noting the CenterPoint Energy transmission grid is a compact and stout system, CenterPoint Energy believes it is highly unlikely many transmission systems can recover to a 0.65 voltage level in 18 cycles (0.30 seconds). To address this, CenterPoint Energy recommends reducing the number of steps. For this, as well as including a 0.9 pu voltage level ride-through for a minimum of 10 seconds, CenterPoint Energy recommends the data points (Time / Voltage) in the “LVRT DURATION” table be as follows: 0.15 / 0.000, 2.00 / 0.450, 3.00 / 0.750, and 10.00 / 0.900.
 
 
 
 
 
Yes
a) CenterPoint Energy is concerned with what appears to be a lack of consistency and coordination between standards efforts. Considering PRC-023, CenterPoint Energy believes it is illogical to have transmission relay loadability requirements based on 0.85 pu system voltage for an extended period (such as, 15 minutes) to allow system operators to take remedial actions, while exempting generators from comparable requirements. For another example, it appears this proposed standard is not consistent with that being proposed for under-frequency load shedding systems that can help prevent cascading outages. b) Requirements, such as R2.2.1 and R2.2.2, are essentially fill-in-the-blank, location-specific criteria that are unnecessary and could have unintended consequences. Location-specific criteria can change over time with additions and modifications of the transmission system. Entities will have no incentives to voluntarily exceed the minimum required criteria, even though their plant has a greater ride-though capability. R2.2.1 further allows relaying to “be set on actual fault clearing times”, instead of the 9 cycles indicated in Attachment 2. In addition, R2.2.2 allows the use of location-specific criteria, but only if such criteria are less stringent. CenterPoint Energy believes NERC reliability standards should not include fill-in-the-blank, location-specific criteria. CenterPoint Energy recommends modifying R2.2.1 to reference Attachment 2 and to clarify the ride-through criteria is zero voltage for 0.15 seconds (9 cycles). CenterPoint Energy recommends deleting R2.2.2. c) R5 allows generating plants to meet less stringent criteria if generator manufacturer literature indicates limitations, which would further erode system support from generation resources. It does not appear there is any process to substantiate the legitimacy of such limitations. CenterPoint Energy recommends deleting R5 and associated references.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
We agree. This is consistent with our view expressed for MOD-026 for which we suggest the Generator Owner, not the Generator Operator, be held responsible for generating unit equipment/device settings and data verification.
Yes
We agree that it is a good start. However, other settings such as those mentioned in the Background Information Section (generator backup over current or impedance, loss of field, etc.) also give rise to tripping of the generator. Consideration should be given to expanding the scope of the SAR to include these settings. The lack of a standard for generator out-of-step protection resulted in adverse effects on the Michigan-Ontario ties during the 2003 blackout.
We are unable to comment on how many generating units in the fleet that are not capable of meeting the threshold in the Attachments since we are not a Generator Owner. However, we are unclear on the basis of the 57.8 Hz setting stipulated in R1.3 as it is not consistent with the proposed UFLS characteristics (posted in July of 2008) in which it indicates that frequency should be arrested at no less than 58.0 Hz. Further, the basis for the very restrictive over-frequency curve proposed in attachment #1 is not obvious. The over-frequency standard proposed in PRC-024 was exceeded during the blackout of 2003 for Ontario generation that was connected radially into New York. No adverse effects attributed to this over frequency event have been reported to the IESO.
 
No
Simulation results only add value when sufficient validation has been performed to provide confidence that good decision can be made on the basis of these simulations. Simulations by themselves are not enough. Were the simulations used in this exercise validated against actual performance? To cater for protection differences within jurisdictions, it would be better to label the jogs in the voltage characteristic with the corresponding physical meaning (e.g. maximum normal fault clearing, maximum delayed fault clearing) rather than assign specific times. Within Ontario, it is unclear whether the voltage curves are sufficient to accommodate present practice for delayed fault clearing. It is unclear in the curves whether the POI voltage is the positive sequence voltage or phase voltage. The meaning of per unit should also be clarified. For example, Ontario uses a 220kV voltage basis for a system operated as high as 250kV. Does 1.2PU mean 264 kV or 300kV? The over-voltage settings should be re-expressed to ensure the short duration over-voltages that follow lightning strikes and capacitor switching do not result in generator tripping.
No
In an islanded situation, each generator's status is critical to ensuring frequency decline is successfully arrested based on the assumption that all on-line generators would not trip within specific frequency bounds unless prior approval has been sought and granted to allow tripping. Not holding the smaller generators subject to the requirements associated with generator frequency tripping exposes the island to a great uncertainty on the amount of generation that can be relied upon to arrest frequency excursion.
No I disagree with the approach
Size dependent VRFs do not reflect the potential reliability risk associated with more than one Medium size generating unit (>100 MVA and <500 MVA) failing to comply with the standard. Two of such units at, say, 400 MVA each, that trip unnecessarily will have a greater collective impact on the island frequency than the tripping of a 500 MVA unit.
No
Please see above comments. We suggest that the same VRFs apply to all units that meet the Applicability criteria.
None
None
Yes
a. R5: The wording "…the Generator Owner is granted an exception for that unit from meeting the portion of Requirement R1 or R2 for that limitation once it provides documentation of the equipment limitation(s) to the Reliability Coordinators, Planning Coordinators, Transmission Operators and Transmission Planners that monitor or model the associated unit, within 30 days of identifying the equipment limitation." is not written in a way to hold an entity responsible for any action. We suggest to reword it such that it places a responsibilility to the Generator to seek approval for an exception, as follows: "…the Generator Owner shall obtain approval for an exception for that unit from meeting the portion of Requirement R1 or R2 for that limitation through the submission of documentation of the equipment limitation(s) to the Reliability Coordinators, Planning Coordinators, Transmission Operators and Transmission Planners that monitor or model the associated unit within 30 days of identifying the equipment limitation." The requirement for getting non-conforming protection approved should be so stipulated to put the onus for mitigating actions on the Generator Owners. For example, in the case of non-conforming underfrequency settings, the requesting Generator Owner should be required to demonstrate that mitigating (i.e. arrangements for additional compensating load shedding) measures have been arranged with the Balancing Authority in their submission. Equipment settings that infringe upon the curves may be implemented only after approval is granted by the appropriate entities. Along with this proposed change, there is also a need for the entities receiving the approval request to respond to the request. Another requirement is needed to complete this process. b. The latter part of R5 should be reworded to hold an entity responsible for the needed actions associated with expiring the exception such that the requirement is measurable and enforceable. c. R6: It is unclear to us what purpose this requirement serves. If R5 is to be revised as we suggest (see above), then the "limitation" in question will be presented with technical justification in the request for approval. The receiving entities (RC, PC, TOP and TP) will have a chance to accept or reject the request with due consideration of the technical argument. This is part of the approval request process, hence we do not see the need for R6 if R5 is to be reworded. If a remand process needs to be stipulated, then inclusion in R5 a requirement for the receiving entity(ies) to respond to the request - either approving or disproving the with a rationale, would suffice.
Individual
Kirit Shah
Ameren
Yes
None
Yes
Please clearly state that such relays do not have to be added or elements enabled, GO makes the decision what protection to include. R1 and M1, and R2 and M2 should allow for proof that the frequency and/or voltage relays are omitted or set to alarm only, not trip. Please clearly define 'point of interconnection' used in 4.2.2; typically this is where the generating source connects to the switchyard or networked transmission system but these relays are typically at the generator terminals on the low side of the generator step-up transformer.
Yes
We have not yet performed a detailed review wrt proposed limits, but expect there will be some that are not capable of meeting these stated thresholds. It can be hard to get capability data and warranties have expired, for older units or those purchased from other owners. The PRC-024-1 curves should not become a de facto requirement. If decades of operating experience have proven satisfactory from both a BES and generator equipment life persperctive, this should be accepted as evidence as well. Generic guidance, such as past ANSI/IEEE standards, recommended practices, and guides should be allowed for older units exception evidence as well. Clearly state that field testing is not required.
 
No
FERC 661-A applies to wind generator Voltage Ride Though (VRT) for a three phase fault. We disagree with PRC-024-1 now expanding it to all generators. R2.2.1 wording is confusing: it implies that the UV trip setting must be less than 9 cycles which conflicts with the LVRT curve and its interpretation for lessor voltage dips.
Yes
Again from our perspective, the main objective is allow UFLS/UVLS to do their job to arrest frequency/voltage decline and retain generation on-line so as not to exacerabate the extreme disturbance. Of course, generation equipment limits must be respected. This standard should not encourage GO to augment protection or become more conservative than warranted, possibly refuting the main objective. We formerly belonged to the now defunct MAIN region. Previous MAIN requirements for generators were: Generator UF Setting (Hz) Minimum Time Delay (Sec) > 59.5 Hz Automatic tripping not permitted < 59.5 to > 59.2 Hz 2700 seconds < 59.2 to > 58.5 Hz 120 seconds < 58.5 to > 58.0 Hz 15 seconds < 58.0 Hz Owner’s Discretion We have applied these to generation that has connected in the last decade unless the GO had manufacturer recommendations to the contrary.
No I disagree with the approach
Are they based on the individual unit or the aggregate at the Point of Interconnection? Average annual production (MWh) is a better indicator of their threat to the BES during UF or UV events. Larger units should not be penalized just because they are large. If large and generating many MWh then they're big and likely to be on-line for an event.
No
See above
It seems that geography (e.g. peninsulas, coastal areas) and load sparcity, and dense load served by distant generation have been significant factors in blackout events. As such, regional differences do exist.
Nuclear Plant Requirements may conflict. Footnote 2 refers to the agreements for which the GO is not responsible. Also, grandfathered generation of more vertically integrated entities and/or in certain states may not have such formal agreements.
Yes
This standard could be ineffective if someone’s auxiliary power protection trips out on low voltage or frequency and brings the unit down before the generator protection. Those settings on the aux buses are there to protect the equipment from failure since most of the downstream loads such as motors and electronics won’t ride through an excursion as well as large T/G sets. We suggest that ANSI/IEEE Standards C37.102, C50.12, and C50.13 should be used and listed as references to this Standard. Reporting mechanism in R3 and R4 raises some commercial concerns. We prefer a secure repository of reporting to the RRO. Then only those who do have valid reasons for studies or monitoring could be granted access to the information. Footnote 1 expands 'protective relays' definition to include voltage regulator, etc. Instead state that only direct trip elements (functions) in the voltage regulator and exciter are included, if that's the intent. It should be made very clear.
Individual
John Cummings
PPL Energy Plus
 
 
 
 
 
 
 
 
 
 
Yes
PPL is concerned with the following concepts in the standard: 1) The standard applies equally to asynchronous and synchronous machines, salient pole and round rotor machines, photovoltaic, and other resources and as such the standard does not appear to recognize that these technologies respond differently to voltage and frequency excursions. 2) Better clarity of generator owner and transmission owner roles regarding changing existing fault clearing times is needed in the proposed standard. 3) R2.2 requires further clarity regarding relay settings. 4) R3 and R4 look the same. 5) The reference paper under Section D needs a thorough review by the industry.
Individual
Robert Jenkins
First Solar
Yes
 
No
The application of the standard to arrays of solar inverters is unclear. While the primary breaker can be set to comply with the standards, when the system voltage is driven to zero during the fault, the inverters will lose their phase lock and begin to shut down.
Yes
The response, and therefore compliance with this proposed Standard, are not clear. The standard does not seem to contemplate static power generators that would be part of renewable energy systems like solar PV. As part of the requirement there should be specificity on a number of points. For example as written it does not clearly define what the generator does during the out of frequency/voltage conditions. Presumably the inverters would not be required to drive current into the fault and thereby increase fault duties. Furthermore, once the fault is cleared, it does not define the speed/rate at which power is ramped up from the generator. This rate could be hard to achieve with a static converter. Finally, the standard does not define the rate of change of frequency or voltage. Typically devices are more sensitive to high rate changes. All of these items need more detail and specificity to determine how new forms of generation can meet these requirements.
 
No
See response to the previous question. While this may envelope the probable range of voltages that may occur on the system, it does not sufficiently describe the response of the generating plant to these disturbances. To simply say that the protective relays should not trip lacks sufficient detail to apply to inverter based PV projects.
 
 
 
 
The requirements are inconsistent with UL 1741 and IEEE 1547 as applied to existing solar PV inverter design. Compliance withn the proposed Standard would require an industry re-design and recognition from the Interconnecting Transmission Owner that projects would not meet these other standards. Additionally the Standard should provide for a phase in period for inverter based PV facilities so that such redesign can be accommodated.
 
Individual
Jay Seitz
US Bureau of Reclamation
Yes
We agree since PRC-004-1, Protection System Misoperation Analysis and Correction and PRC-005-1, Protection System Maintenance, are applicable to the Generator Owner (and Transmission Owner); however, PRC-001-1 Protection System Coordination is applicable to the Generator Operator (and Transmission Operator). We believe all of the above should be coordinated and applicable to the Owner. The Standard also has a role for a Transmission entity (in this case the Transmission Planner) to specify clearing times; however no applicability or requirement is provided in the standard. We believe the role for a Transmission entity should be clarified in the Standard and applicability and requirement(s) added.
No
Now that the draft standard has been posted, it appears to be a more structured and limited version of existing Standard PRC-001-1 - System Protection Coordination. PRC-001-1 requires the Generator entity to coordinate protection settings with the Transmission entity. The stated Purpose of PRC-024-1 "Ensure that generator frequency and voltage protective relays are set to support transmission system stability during voltage and frequency excursions" should be attainable through PRC-001-1. If PRC-001-1 is not adequate it should be modified rather than adding an additional standard only addressing generator frequency and voltage settings. As such we do not believe there is a clear, reliability based justification for this standard as currently drafted.
No
 
 
No
The SDT background material above states that the 9 cycle time is required by FERC Order 661-A. FERC Order 661-A applies to wind generators. We believe there is no convincing reliability based rationale to expand the scope of the FERC Order via this standard to include synchronous machines, noting that Genrators are already required (PRC-001-1) to coordinate settings with the host Transmission Operator.
Yes
The threshold should be consistent with the NERC Reliability Compliance Registry Criteria.
No I disagree with the approach
If this approach is appropriate for this standard, it seems this approach should be used for all Standards applicable to generators.
 
 
 
Yes
Requirements R3 and R4 place a coordinating role on the Generator Owner to provide trip settings to four entities, the Reliability Coordinator, Planning Coordinator, Transmission Operator, and Transmission Planner. We believe it is more appropriate for the Generator Owner to coordinate settings with a single Transmission entity since the purpose of the Standard is " ... to support transmission system stability during voltage and frequency excursions." and for the Transmission entity to further coordinate if necessary. The Transmission entity is in a better position to know what additional entities, if any should be involved. For the data points provided in the Attachment 2, HVRT DURATION and LVRT DURATION, we recommend both time and voltage units of measure be provided.
Individual
Jason Shaver
American Transmission Company
Yes
 
Yes
 
No
ATC does not own any generation
 
Yes
 
Yes
 
Yes I agree with the approach
 
Yes
 
 
 
No
t would be beneficial to have the option of measuring the voltage at the generator bus or point of interconnection (POI), with the understanding that the proper voltage must be maintained at the POI.
Group
IRC Standards Review Committee
Ben Li
IESO
Yes
We agree. This is consistent with our view expressed for MOD-026 for which we suggest the Generator Owner, not the Generator Operator, be held responsible for generating unit equipment/device settings and data verification.
Yes
We agree that it is a good start.
No
We are unable to comment on how many generating units in the fleet that are not capable of meeting the threshold in the Attachments since we are not a Generator Owner. However, we are unclear on the basis of the 57.8 Hz setting stipulated in R1.3 as it is not consistent with the proposed UFLS characteristics (posted in July of 2008) in which it indicates that frequency should be arrested at no less than 58.0 Hz. We also think the question is a bit misleading and may not result in providing the SDT any grounded suggestions or concurrence on the appropriate frequency levels that the SDT may already have in mind. The question as written suggests that the SDT is trying to canvass the industry through this commenting process. This is a way to obtain feedback, but it does not provide the rationale of the proposed levels. We suggest that the SDT research the limitations of the machines that are connected to the BPS (perhaps by a survey or a NERC data request) to better support the proposed frequency limit, then ask for concurrence or alternative suggestions.
 
Yes
From a system operator's perspective, we think these parameters are appropriate to prevent unnecessary tripping of the generators, which may otherwise give rise to unreliability, while minimizing their expose to prolonged period of under and overvoltages.
No
There should not be any exemption of the coordination on frequency trip setting. In an islanded situation, each generator's status is critical to ensuring that frequency decline is successfully arrested based on the assumption that all on-line generators would not trip within specific frequency bounds unless prior approval has been sought and granted to allow tripping. Not holding the smaller generators subject to the requirements associated with generator frequency tripping exposes the island to a great uncertainty on the amount of generation that can be relied upon to arrest frequency excursion.
No I disagree with the approach
Size dependent VRFs do not reflect the potential reliability risk associated with more than one Medium size generating unit (>100 MVA and <500 MVA) failing to comply with the standard. Two of such units at, say, 400 MVA each, that trip unnecessarily will have a greater collective impact on the island frequency than the tripping of a 500 MVA unit.
No
Please see above comments. We suggest that the same VRFs apply to all units that meet the Applicability criteria.
None
None
Yes
a. R5: The wording "…the Generator Owner is granted an exception for that unit from meeting the portion of Requirement R1 or R2 for that limitation once it provides documentation of the equipment limitation(s) to the Reliability Coordinators, Planning Coordinators, Transmission Operators and Transmission Planners that monitor or model the associated unit, within 30 days of identifying the equipment limitation." is not written in a way to hold an entity responsible for any action. We suggest to reword it such that it places a responsibility to the Generator to seek approval for an exception, as follows: "the Generator Owner shall obtain approval for an exception for that unit from meeting the portion of Requirement R1 or R2 for that limitation through the submission of documentation of the equipment limitation(s) to the Reliability Coordinators, Planning Coordinators, Transmission Operators and Transmission Planners that monitor or model the associated unit within 30 days of identifying the equipment limitation. Along with this proposed change, there is also a need for the entities receiving the approval request to respond to the request. Another requirement is needed to complete this process. b. The latter part of R5 should be reworded to hold an entity responsible for the needed actions associated with expiring the exception such that the requirement is measurable and enforceable. c. R6: It is unclear to us what purpose this requirement serves. If R5 is to be revised as we suggest (see above), then the "limitation" in question will be presented with technical justification in the request for approval. The receiving entities (RC, PC, TOP and TP) will have a chance to accept or reject the request with due consideration of the technical argument. This is part of the approval request process, hence we do not see the need for R6 if R5 is to be reworded. If a remand process needs to be stipulated, then inclusion in R5 a requirement for the receiving entity(ies) to respond to the request - either approving or disproving the with a rationale, would suffice.