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Question 1  (52 Responses)
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Question 2  (54 Responses)
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Question 3  (52 Responses)
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Question 4  (47 Responses)
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Question 5  (45 Responses)
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Question 6  (49 Responses)
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Question 7  (48 Responses)
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Question 8 Comments or Conflict  (55 Responses)
Question 9  (10 Responses)
Question 9 Comments  (55 Responses)
Question 10  (0 Responses)
Question 10 Comments  (55 Responses)
 
Individual
James Starling
SCE&G
Yes
The SDT is to be commended for developing a clear and well documented draft. Overall it provides a balanced view of Protection System Maintenance, and good justification for its maximum intervals.
No
Table 1a – Level 1 Monitoring has a requirement to “Verify the continuity of the breaker trip circuit including trip coil” at least every 3 months. This is interpreted to be applicable to both the low-side generator output breaker and the high-side breaker for the GSU. The generator output breaker has 3 separate trip coils (one for each pole) that are connected in a parallel configuration and there is no means available to verify continuity of each of these coils INDIVIDUALLY in this arrangement. Is the intent of this requirement to have each trip signal parallel leg verified every three months even though the trip contacts are normally open (these circuits are functionally checked during LOR Functional Verification)? Also, is the Red Indication Light (RIL), which includes the trip coil in the power circuit, adequate for verification (note that the breaker does not include the parallel legs that contain the tripping sensor contacts)? Also, more clarification is needed on the section “Verify proper functioning of the current and voltage circuit inputs from the voltage and current sensing devices to the protective relays” under “Voltage and Current Sensing Devices Inputs to Protective Relays.” How would this be done if no redundancy is available for cross-checking voltage and current sources? In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent with the entities procedures should be adequate to indicate compliance.
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year. We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months. Other methods of achieving the same result is to state periodic requirements of quarterly or 4 times per year.
No
Several maximum maintenance intervals are 3 months. Since this is an absolute maximum period, entities would need to schedule on a 2 month basis to assure the 3 month maximum is met, i.e., 6 times per year. We recommend that 3 month periods be increased to 4 months which allows scheduling every 3 months. An alternate method of achieving the same result is to state periodic requirements of quarterly or 4 times per year.
Yes
 
No
 
The FAQ should be expanded to address the issues raised above with verification of trip circuits as to what is an acceptable method meeting the intent of the standard We also suggest changing “prove” to “verify” on FAQ 3a to be consistent with the wording of the requirement. Also, for a single bus with one set of bus potential transformers, how does one verify proper functioning of the potentials? Is a reasonableness criterion adequate?
 
 
 
Individual
Rick Koch
Nebraska Public Power District
Yes
 
No
Table 1a, for Protective Relays identifies the following Maintenance Activities: Test and calibrate the relays (other than microprocessor relays) with simulated electrical inputs. Verify proper functioning of the relay trip outputs. What is the difference between these two requirements? They appear to be practically equivalent. Tables 1a & 1b, for Station DC supply identify the following Maintenance Activity: Measure that specific gravity and temperature of each cell is within tolerance (where applicable). What is the advantage of testing the SG in every cell compared to using a pilot cell as representative sample of the entire bank? NPPD has not experienced any problems using a pilot cell compared to testing every individual cell. Typically, if the SG is low the cell voltage will be low, which is detected by the voltage test. This seems to be an excessive requirement and does increase personnel exposure to hazardous fluid. What unique information is provided by this test that other tests do not provide?
No
Table 1a, for Station DC supply (that has as a component Valve Regulated Lead-Acid batteries) establishes a Maximum Maintenance Interval of 3 Calendar Years for the following Maintenance Activity: Verify that the station battery can perform as designed by conducting a performance or service capacity test of the entire battery bank. What is the basis for this interval? NPPD’s experience indicates that a 5 Year interval is adequate, especially during the early service life of the battery bank, with increasing frequency as the bank ages.
Yes
 
Yes
 
No
 
Yes
On page 17, the answers to questions 2B and 2C indicate that there is no allowance or provision to exceed the Maximum Maintenance Interval under any circumstances, except that natural disasters or other events of force majeure will receive special consideration when determining sanctions. The rigidity of this performance requirement could conceivably require equipment to be tested even though it is out of service in order to remain compliant, adding unnecessary cost and waste to the PSMP of the regulated entities. We believe that a prescriptive process for deferring testing and maintenance beyond the stated interval would be beneficial to allow the necessary flexibility to manage the PSMP effectively.
None
None
Definition of Terms: Footnote 2 for R4 defines a "maintenance correctable issue". This should be added to the Definition of Terms section. Sections 4.2.5.4 and 4.2.5.5 inappropriately extends Generator Protection Systems to Station Service Transformers. These are components necessary for plant operation however they are not part of the generator protection scheme. This conclusion is supported by the explanations on page 16 of the FAQ. The FAQ states the operation of the listed station auxiliary transforms protective relays would result in the trip of the generating unit and, as such, would be included in the program. The FAQ goes on to state that relays which trip breakers serving station auxiliary loads such as pumps, fans, or fuel handling equipment, etc., need not be included in the program even if the loss of those loades could result in a trip of the generating unit. The FAQ appears to be inconsistent. Station auxiliary transformers are included because they would result in the trip of the generating unit while other loads such as pumps, fans, etc., are excluded even if their trip could result in a trip of the generating unit. In my opinion, the station service transformers like pumps, fans, etc. are components necessary for plant operation but not necessary for generator protection and should therefore be excluded from PRC-005-2 by removing Sections 4.2.5.4 and 4.2.5.5 from the Standard and modifying the FAQ accordingly. R1 (1.1) First sentence: "For each component used in each Protection System,..." is ambiguous. The sentence should be revised to say..."For each Protection System component, include all maintenance activities specified in Tables 1a, 1b, and 1c." This limits the components to only those identified by the definition of a Protection System. R2 End of sentence: "possess the necessary monitoring attributes." is ambiguous. The sentence should be revised to say..."possess the monitoring attributes identified in Tables 1b or 1c." This specifically defines which attributes are necessary. R4 I am concerned with including the phrase "including identification of the resolution of all maintenance correctible issues". Providing evidence of implementation of the PSMP will require the collection and submittal of all work documents that restored a device to functional order by calibration, repair, or replacement. It is reasonable to assume that appropriate corrective actions were taken for each specific situation. Identification of the resolution will add a significant documentation burden without adding to the reliability of the BES. Implementation of the PSMP may be evidenced without including identification of the resolution of all maintenance correctible issues. It is interesting to note that nowhere in PRC-005-2 does it state that you have to take corrective actions to return a component to normal operating conditions. "No action taken" can be the resolution taken by the utility of a maintenance correctible issue.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
 
No
What documentation or evidence is required to prove that the Protection System Control Circuitry has been maintained every three months, if just a visual inspection of the breaker control trip circuit RED panel light has been completed, to verify continuity of breaker trip coil? How do we handle breakers with dual trip coils and only one RED light for trip coil continuity? What do the terms DISTRIBUTED and CENTRALIZED with respect to UFLS mean? In Table 1C under the heading "Maximum Maintenance Interval" some of the entries are stated as being "Continuous". In the case of other maintenance activities the descriptor for Maintenance Interval indentifies the maximum period of time that may elapse before action must be taken. "Continuous" implies continuous action; however, in reality continuous monitoring enables no maintenance action to be taken until such time as trends indicate the need to do so. Therefore we recommend that where the maintenance interval is stated as "Continuous" it should be changed to read "Never" or "Not Applicable". The Table 1A requirement of 3 months for Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) should be omitted as it is not realistic. Recommend following the Table 1B requirement of 6 years (Trip testing) for this. Does 27 undervoltage monitoring of this circuit qualify as self monitoring?
No
When we have redundant digital relay system that would fall under Level 1c category with a 12 year mtce cycle, but the Protection System Control Circuitry is non-monitored so it falls under Level 1a, with a 6 year mtce cycle. We will have to complete relay mtce and trip testing every 12 years and trip testing only every 6 years, therefore we must complete trip testing twice as often as we are doing the maintenance. We feel that relay maintenance and trip testing should be completed at the same frequency. The Protection System Control Circuitry (Breaker Trip Coil) checks every three months is too excessive. These circuits are checked during trip testing of the Protection scheme, at the 6 or 12 year interval. If we have a redundant digital relay system, using a IEC61850 communication from the relay to a common breaker aux trip relay, what level does this system fall under?
Yes
 
Yes
 
No
 
Yes
 
 
 
 
Individual
Kristina Loudermilk
ENOSERV
Yes
 
No
Table 1A, protective replays for 6 calendar years, Testing and calibrating the relays other than microprocessors relays with simulated electrical inputs... does that mean that micro processor relays do not need to be checked? Verify proper function of the relay trip outputs... Does this involve both electro AND micro processors? Then when mentioning the verifying microprocessor relays, does that include the trip output.
Yes
 
Yes
 
Yes
 
No
 
No
 
 
 
On Table 1A, the maximum time lengths are too long, especially for electro relays. A prime example is when testing a KD relay on a yearly basis and most of the time needs to be adjusted because of how far off it comes out. Allowing entities to take their time up to six calendar years may be too long.
Individual
Wade Davis
Otter Tail Power
Yes
 
No
Station DC supply - (Maintenance Activity) As a company we do not think that measuring specific gravity and temperature of each cell is necessary. Their is a better test that we use with the Bite Impedance Test. We have had good success with the impedance test for determining the batteries condition. See article (Impedance Testing Is The Coming Thing For Substation Battery Maintenance)written in Transmission & Distribution 11/1991 by Ritchard Kelleher, Test & Maintenance Specialist, Northeast Utilities.
Yes
 
Yes
 
 
 
 
 
 
 
Individual
Alison Mackellar
Exelon Generation Company, LLC - Exelon Nuclear
Yes
None
No
1. Minimum maintenance activities should be on a yearly multiplier verses a monthly multiplier. Nuclear generating stations are typically on an 18-month or 24-month refueling cycle. The draft standard does not take into consideration a nuclear generators refueling cycle. Specifically, most Boiling Water Reactors (BWRs) are on a 24-month refueling cycle and may run continuously between refueling outages. Performing maintenance on-line puts the generating unit at risk without any commensurate increase in reliability to the bulk electric system. 2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing programs. 3. Activities that begin with "verify" should be modified to "Validate_________are/is within acceptable limits. Initiate corrective actions as required." For example, some level of DC grounds are acceptable based on circuit design and component installation. Troubleshooting or ground isolation may increase the risk to the system depending on ground magnitude and conditions. 4. Please provide clarification on "verify that no dc supply grounds are present" most stations have some level of ground current. Should this be interpreted to be a measure of resistance or current values? Suggest rewording to say "Check and record unintentional battery grounds" 5. "Verify Station Battery Chargers provides the correct float and equalize voltage" should be deleted. Equalizing a battery is a maintenance function and should only be performed as needed. Suggest rewording to say "Check and record charger output current and voltage." 6. Activities associated with Battery Charger performance should be deleted. The ability of the Battery Charger to maintain the battery at full charge state is verified by checking proper "float voltage." The ability to provide full rated current only affects the ability to recharge a battery AFTER an event has occurred. 7. In Table 1a does the requirement to "verify proper electrolyte level" refer to all batteries or only a sampling? Current practice is to use the "pilot cell" as the monitoring cell as this cell is usually the least healthy of the battery bank from a specific gravity and/or voltage standpoint. If the pilot cell continues to degrade then the other batteries will be monitored more often. Suggest rewording to "Check electrolyte level." 8. In Table 1a the 18-month requirement to measure that the specific gravity and temperature of each cell is within tolerance is "where applicable" – what does "where applicable" mean? 9. For the Station dc supply (battery is not used) 18-month interval – should this be interpreted that it is just the battery charger with no attached battery? Or a dc supply system that does not contain a battery? 10. Table 1a Station dc supply 18-month interval to verify cell-to-cell and terminal connection resistance is within "tolerance" should be revised to say "tolerance or acceptable limits." 11. Table 1a Station dc supply (that has as a component valve regulated lead-acid batteries) should provide an additional optional activity for "Total replacement of battery at an interval of four (4) years" in lieu of not conducting performance or service capacity test at maximum maintenance interval.
No
1. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing programs. 2. Table 1a – page 6 regarding the 3 Month "Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS)" states that the maintenance activity shall verify the continuity of the breaker trip circuit including the trip coil. There is unclear guidance on how this activity is to be performed, particular on generator output breakers. Does this activity imply actual trip testing of the breaker itself? If so, performing this type of activity with the generator on-line puts the unit at risk without any commensurate increase in reliability to the bulk electric system. If this is the case it is requested that this particular test is extended from 3 months to 24 months to align with nuclear generating units refueling cycle. If not, and this activity is simply verification of continuity by means of light indication, then please clarify in Table 1a.
No
1. Please provide more clarification on what constitutes "partially monitoring." For example, is a computer auxiliary contact alarm count as partial monitoring? Would a common alarm between relays meet the definition of partial monitoring? 2. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing programs. 3. Table 1b Station dc supply (that has as a component valve regulated lead-acid batteries) should provide an additional optional activity for "Total replacement of battery at an interval of four (4) years. 4. There seems to be a disconnect between the monitoring attribute and maintenance activity. For example, the monitoring attribute "Monitoring and alarming of the station dc supply voltage/detection and alarming of dc grounds" has the maintenance activity "verify that the station battery can perform as designed by conducting a performance or service capacity test of the entire batter bank. (3 calendar years) – or – Verify that the station battery can perform as designed by evaluating the measure cell/unit internal ohmic values to station battery baseline (3 months)." The maintenance activity does not support the monitoring attribute. 5. If an entity has implemented Table 1b and/ or Table 1c, is there an acceptable length of time that the monitoring equipment can be out of service without falling back to Table 1a requirements?
Yes
None
No
None
No
None
Conflict 1. Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission (NRC). Each licensee operates in accordance with plant specific Technical Specifications (TSs) issued by the NRC. TS allow for a 25% grace period may be applied to TS Surveillance Requirements (SRs). Referencing NRC issued NUREGs for Standard Issued Technical Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability, SR 3.02 states the following: " The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met." 2. Battery Charger Testing 3. All conditions (grounds, voltages etc) should be compared to "acceptable limits" as specified in nuclear station design basis documents, industry standards or vendor data. 4. IEEE 450 does not use the word "proper" as utilized in Table 1a (e.g., "record voltage of each cell v/s verify proper voltage of each individual cell….") 5. The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to ensure reliable operation of equipment within the scope of the Rule. Adjustments are made to the PM (preventative maintenance) program based on equipment performance. The Maintenance Rule program should provide an acceptable level of reliability and availability for equipment within its scope. Comments: 1. All maintenance activities should include a "grace" period to allow for changes to a nuclear generator's refueling schedule and emergent conditions that would prevent the safe isolation of equipment and/or testing of function. "Grace" periods align with currently implemented nuclear generator's maintenance and testing programs. 2. The 3-month maximum interval should be extended to include a grace period to ensure that a 25% grace period is included to align with current nuclear templates that implement NRC TS SRs are documented in the response to Question 8.
Business Practice
Business Practice: Nuclear Electric Insurance Limited (NEIL) variance allowance.
1. Battery testing should be added to Table 1c for Station dc supply (that uses a battery and charger) 2. Table 1c – Condition based maintenance. Consider adding Battery Capacity Test on a 6-year interval regardless of other condition based maintenance performed. 3. Evaluating the measured cell/unit internal ohmic values to station battery baseline does not provide an evaluation of battery capacity – please explain rational for maintenance activity. 4. If the Table 1a maintenance interval is reached and the entity is unable to perform the maintenance task, is it acceptable to install temporary external monitoring or other measures to defer the maintenance to Table 1b or Table 1c interval? Is it acceptable in Table 1b to substitute additional or augmented maintenance activities or operator rounds to extend intervals? 5. Table 1c for equipment with "continuous monitoring" states the maximum maintenance interval of "continuous" – this does not seem correct wording – consider revising to state "not required." 6. The NERC Standard should be revised to include a specific allowance for a deferral or variances of a maintenance activity based on a formal technical evaluation. Nuclear generating units allow for deferrals and/or variances on certain equipment based on emergent conditions that would prevent safe isolation and/or testing of function. It should be noted that any deferrals and/or variances if justified are to be based on a formal evaluation and not based on work management or resource issues. 7. The maintenance intervals and maintenance activities should be referenced directly to a basis document to ensure guidelines have a specific technical basis (e.g., IEEE-450).
Group
SERC Protection and Controls Sub-committee (PCS)
Joe Spencer - SERC staff
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally provides a well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum intervals.
Yes
We agree with the majority of the activities. Below is an example where clarification is needed. “Verify proper functioning of the current and voltage circuit inputs from the voltage and current sensing devices to the protective relays” under “Voltage and Current Sensing Devices Inputs to Protective Relays.” How would this be done if no redundancy is available for cross-checking voltage and current sources? In certain situations, “verify proper functioning” is not clear enough. Documentation of verification consistent with the entities procedures should be adequate to indicate compliance.
No
Recommend that all Level 1 three-month maintenance intervals be changed from 3 months to quarterly. Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would result in six inspections per year. In the experience of many of our utilities, four inspections per year have proven to be successful.
No
Recommend that all Level 2 three-month maintenance intervals be changed from 3 months to quarterly. Given a 3 month maximum interval an entity would need to schedule these tasks every 2 months. This would result in six inspections per year. In the experience of many of our utilities, four inspections per year have proven to be successful.
Yes
 
No
 
Yes
Change “prove” to “verify” on FAQ 3a (under Voltage and Current Sensing Devise Inputs to Protective Relays) to be consistent with the wording of the requirement.
None known.
Regional Variance
It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System” would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the specific protection that would be considered part of the “Transmission Protection System” would also depend on the regional definition of the BES. We suggest that the regions develop a supplement that provides further clarification on what constitutes a “Transmission Protection System” given the regional definition of the BES.
The “zero tolerance” structure proposed combined with the large volume and complexity of Protection System components forces an entity to shorten their intervals well below maximum. We instead propose a calendar increment carryover period in which a small percentage of carryover components would be tracked and addressed. For example, up to 1% of an entity’s communication channel 6 year verifications could carryover into the next year. These carryover components would be addressed with high priority in that next calendar increment. There are many barriers to 100% completion or zero tolerance. Some utilities have over ten thousand components.
Group
NextEra Energy Resources
Benjamin Church
Yes
 
No
a. Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002. b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System. c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”. Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not maintained? d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require actual tripping of circuit breakers? e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current and their respective phase angles be measured at each discrete electromechanical relay? f. NextEra Energy concurs with other entities comments concerning this question: This entity believes the approach taken by the SDT is overly prescriptive and too complex to be practically implemented. The inflexible “minimum maintenance activities” approach fails to recognize the harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program based on their configurations and operating experience. In particular, the loss of maintenance flexibility embodied in this approach would have perverse consequences for entities with redundant systems. Entities with redundant systems have less need for maintenance of individual components (due to redundancy) yet have twice the maintenance requirements under the “minimum maintenance activities” approach. For example, Table 1A calls for performing a specific gravity test on “each cell’ of lead acid batteries. Our company believes such a requirement is dubious for entities that do not have redundant batteries, and absurd for entities that do. We have installed redundant batteries in most locations and has had an excellent operating history with batteries by using a combination of internal resistance testing and specific gravity testing of a single “pilot cell”. This practice, combined with DC system alarming capability, has worked well. We are opposed to approving a standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To clarify this last point, we are not asserting that maintenance problems do not exist. However, requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal, regardless of how existing practices are working, is not an appropriate solution. Among other things, requiring entities to modify practices that are working well to conform to the rigid requirements proposed herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements, degrade reliability performance. Arguably, an entity could possibly return to its existing practices, if those practices are working well, by navigating through the complex set of options and supporting documentation that the SDT has crafted in this proposal. However, like many entities, we have an army of substation technicians with various ranges of experience to perform maintenance on protective systems and other substation components. It is unrealistic to expect most entities making a good faith effort to comply with this proposal to have a full understanding throughout the entire organization of all the nuances crafted into this complex proposal. For the reasons outlined above, we do not agree with the proposal to specify minimum maintenance activities. However, if the majority of industry commenters agree with the SDT’s proposal, we have concerns about some of the proposed minimum tasks. For Protection System control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The “Frequently-asked Questions” document states that this “may be an overall test that verifies the operation of the entire trip scheme at once, or it may be several tests of the various portions that make up the entire trip scheme”. Such a requirement creates its own set of reliability risks, especially when monitoring already mitigates risks. We are concerned with this standard promoting an overall functional trip test for transmission Protection Systems. This type of testing can negatively impact reliability with the outages that are required and by exposing the electric system to incorrect tripping. Our company views overall functional trip testing as a commissioning task, not a preventive maintenance task. We perform such testing on new stations and whenever expansion or modification of existing stations dictates such testing.
No
a. (i) Protective relays, (ii) Protection Control Circuitry (Trip Circuits) and (iii) Protection System Communications Equipment and Channels should be changed from 6 calendar years to 8 calendar years. Based on FPL Group’s experience and Reliability Centered Maintenance (RCM) program, FPL Group has established an 8 year program and has found that an aggressive 6 year program would not substantially increase the effectiveness of a preventative maintenance program. b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past. c. The maximum maintenance interval for communications equipment should be changed from 3 months to 12 months. Based on FPL Group’s experience and RCM program, FPL Group has established a 12 month program that is effective. d. Additionally, NextEra Energy concurs with other entities comments concerning this question: Imposing inflexible maximum interval requirements has the same basic problems as imposing inflexible minimum task requirements. The inflexible “maximum interval” approach fails to recognize the harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program based on their configurations and operating experience. The maximum interval approach also has same perverse consequences for entities with redundant systems as the minimum interval approach. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in this standard have a maximum interval of 3 months, which is problematic under normal circumstances and unworkable when routine maintenance activities have a much lower priority than emergency repair and restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for Vegetation Management does include such allowances for natural disasters, such as tornados and hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an overly prescriptive maximum interval approach remains.
Yes
 
Yes
 
No
 
Yes
a. NextEra Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13 pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and complex for most entities to practically implement. NextEra Energy would prefer the SDT leave the existing requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT attempt to simplify it. 7. The Standard Drafting Team has provided a “Frequently-asked Questions” document to address anticipated questions relative to the standard. Do you have any comments on the FAQ? Please explain in the comment area. 1 Yes 0 No Comments: a. An alternative to measuring battery specific gravity is to measure float voltage and float current as described in Annex A4 of IEEE Std 450-2002. b. FAQ Page 17 (#1B): It is outside the jurisdiction of the standards development team to determine acceptable forms of evidence. This should be decided by the Regional Entities. c. FAQ Page 15 (#1A): This question should not have been included since it is addressing the definition of BES, which is currently being addressed by another NERC Group. d. FAQ Page 15 (#2): Although the FAQ is not enforceable, the answer provided may be interpreted as enforceable. This should be included in the standard and not in the FAQ.
 
 
a. The level of effort that will be required to be in compliance in accordance to PRC-005-2 is substantial. Also, it will be difficult to create one maintenance program for all NextEra Energy sites that establishes maintenance intervals based the implementation of a combination of the three allowable types of maintenance programs (time-based, condition based, and/or performance based maintenance). As a result, a high risk exists that something will be missed or carried out incorrectly. b. What is the implementation period? How will the standard be implemented in relation to the entity’s maintenance scheduled in accordance with existing intervals specified in the current Protection System Maintenance and Testing Procedure that meets the requirements of PRC-005-1 but will exceed PRC-005-2’s established maximum intervals? Once PRC-005-2 becomes mandatory, entities should not be required to re-do testing in accordance with the new intervals. Instead, entities should be allowed to implement the newly established intervals after the last known cycle. c. Protection System Maintenance Program (PSMP): (c1) The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection System components are kept in working order and where malfunctioning components are restored to working order.” (c2) Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”? (c3) The definition of Restoration would also be more explicit if changed to “The actions to return malfunctioning components back to working order by calibration, repair or replacement. (c4) Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be compliant? d. Protection System (modification): (d1) ”Voltage and current sensing inputs to protective relays” should be changed to “voltage and current sensors for protective relays.” Voltage and current sensors are components that produce voltage and current inputs to protective relays. (d2) “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary Reference. (d3) The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that are clear and concise. e. Additionaly, NextEra Energy concurs with the following comments made by other entities: (e1) PRC-005 Sect B (R2): More clarity needs to be provided. Does this requirement require the utility to document the capabilities of its various protection components to determine fully and partially monitored protection systems? If so the requirement for such documentation should be clearly spelled out. Usually each requirement has a measurement (of compliance) and I'm not clear how this will be done. (e2) PRC-005 Sect B (R4.1): A “grace period” similar to the NPCC Criteria should be considered in case it is not possible to obtain necessary outages.
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
 
No
IMPA does not agree with the battery charger testing requirements. Per the battery charger manual, the manufacturer sets the current limit at the factory, and it only needs to be adjusted if a lower current limit is desired. The manufacturer gives directions on how to lower the current limiter, and the directions seem to be for this purpose only (not for the sole purpose of performing a current limiter test). The manufacturer also does not give directions on how to perform a full load current test and does not give any recommendation to the user that such test is needed. IMPA believes that both of these maintenance items are not needed to maintain the battery charger and that only the manufacturer's recommendations on maintenance and testing need to be followed.
 
 
 
 
 
 
 
 
Group
Green Country Energy LLC
Rick Shackleford
Yes
 
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations on operating units. System configuration of many plants will require an extensive interruption of total plant production to complete the test. 2)Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations on operating units. System configuration of many plants will require an extensive interruption of total plant production to complete the test.
No
1) Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) also The maintenance activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations on operating units. System configuration of many plants will require an extensive interruption of total plant production to complete the test. 2)Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS systems only) The maintenance activity causes excessive breaker operation, and the intrusive nature increases the risk of subsequent misoperations on operating units. System configuration of many plants will require an extensive interruption of total plant production to complete the test.
No Preference at this time.
N/A does not apply
Yes
Huge help to us!
No
 
It would be beneficial to include some administrative (man hour) and cost estimates to comply with this and any future proposed standards so if major budget impacts could be addressed.
Business Practice
Contractual commitments existing prior to NERC stds make it difficult to comply with some of the maintenance activities.
None
Group
Northeast Power Coordinating Council
Guy Zito
Yes
 
No
We agree there is a need for minimum maintenance activities; however, the standard does not clearly define the differences between Table 1a, 1b, and 1c. It is recommended that the drafting team develop definitions for the equipment listed in these tables. For example, Table 1a equipment consists of mechanical and solid state equipment without monitoring capability, Table 1b consists of mechanical and solid state equipment with monitoring capability, and Table 1c consists of equipment capable of self monitoring. In addition, all battery, charger and power supply maintenance activities should be removed from Table 1a, 1b, and 1c, and summarized in a separate Table (i.e. Table 2). Tables 1a and 1b for 'Station dc supply (that has as a component any type of battery) and Table 1c for 'Station dc Supply (any battery technology) for an 18 Month 'Maximum Maintenance Interval' identifies the need to 'Measure that the specific gravity and temperature of each cell is within tolerance (where applicable).' Following industry best practices, we would recommend using the MBRITE diagnostic test. MBRITE testing provides more information than a specific gravity test while reducing the risk of injury to testing personnel. In Table 1a, the Type of Component “Protection system communications equipment and channels.” has a 3 month “Maximum Maintenance Interval”. Clarification needs to be provided as to how an unmonitored (do not have self-monitoring alarms) will be tested. Table 1a refers to “Unmonitored Protection Systems”. The “6 Calendar Years” “Maximum Maintenance Interval” “Maintenance Activities” is excessive.
No
We question whether any maintenance activity should be as long as 12 years. Considering the rate of change in personnel and technology, the working group should reduce the time period by redefining the requirement if necessary, or eliminate the standard requirement. In addition, the DC components have too many tests at confusing intervals. Confusion will make it difficult to implement or follow the exact method used.
Yes
 
No
The concept is acceptable, but the requirements to follow in Appendix A seem to be a deterrent from attempting to use this process. Is the term “common factors” meant to take into account variables at locations that can affect the components’ performance (lightning, water damage, humidity, heat, cold)?
No
 
Yes
The FAQ is helpful in answering many of the obvious questions.
Yes--NPCC Directory #3, NPCC Key Facility Maintenance Tables. All areas must implement changes at the same time.
Not aware of any regional variance or business practice.
• Requirements 4.2.5.4 and 4.2.5.5 require clarification. It is recommended that the drafting team provide a schematic diagram to provide clarity as to which generator and system connected transformers are included in this facility identification. • When Measures are added to the Standard, the Standard Drafting Team must consider how the owner will be required to assess and document the decision of which table will apply to each protection. While this is a compliance element, the Standard should provide clarity on this matter. As written, the requirement does not seem to be measurable. • Requirement R4 requires clarification on what is meant by “including identification of the resolution of all maintenance correctible issues as follows:” Correctible issues should not be combined in the same sentence with the layout of the tables. • Table 1b: In the section for “Protection system communication equipment and channels”, there needs to be clarification on “verify that the performance of the channel and the quality of the channel meets the performance criteria, such as via measurement of signal level, reflected power, or data error rate.” This may be done as a pass fail test during trip checks. If the communication line successfully sends proper signals for the trip checks, then the communication line is acceptable and no additional measurement are taken. • Table 1c: There is some confusion on what is expected on items that have a Maximum Maintenance Interval reported as “Continuous”. For example, a component in the “Protection System telecommunication equipment and channels” how would one provide documentation or proof of the continuous verification of the two items listed in the maintenance activities? In other words how does one prove “Continuous verification of the communication equipment alarm system is provided” and “Continuous verification that the performance and the quality of the channel meet the performance criteria is provided”. These activities appear to be “monitoring attributes” more so than they are maintenance activities. Additionally, the Continuous “Maximum Maintenance Interval” needs clarification because: o the interval is a monitoring interval and not a maintenance interval o a strict interpretation of “Continuous” could require redundant monitoring systems be installed or locations staffed by personnel to monitor equipment in the event remote monitoring capabilities are unavailable o It is unclear how to provide proof to an auditor that continuous monitoring has occurred over a given interval • Table 1a, 1b, and 1c: The maintenance activity for battery chargers are to perform testing of the charger at full rated current and verify current-limit performance. The drafting team should provide an industry standard as how to perform this check, or specify an industry equivalent test. • The Table 1b Level 2 Monitoring Attributes for Component “Monitoring and alarming of continuity of trip coil(s)” should be changed to read “Monitoring and alarming of continuity of all DC circuits including the trip coil(s)”. The present wording is confusing and can be interpreted to mean that the DC control circuitry needs to be checked every 12 years, as opposed to what we perceive to be the intended 6 years. • The Maintenance Activities in Table 1c are not consistent with the Level 3 Monitoring Attributes for Component “Protection system telecommunications equipment and channels.” “Continuous verification of interface to protective relays” should be added as a third activity should be added under the Maintenance Activities column. • In Section A. Introduction, 4.2.4 should be made to read “Protection System components which are installed as a Special Protection System for BES reliability.” • For Requirement 4.1, a “grace period” similar to the NPCC criteria should be considered in case it is not possible to obtain any necessary outages to get the prescribed maintenance done. • Requirement R1 should be modified to read “Each Transmission Owner, Generator Owner, and Distribution Provider shall develop, document, and implement a Protection System Maintenance Program (PSMP) for its Protection Systems that use… This revision reinforces what is necessary to ensure proper compliance with the program. • The standard has multiple component tests required at different and conflicting intervals, some interdependent. Preference is to have the component listed with a common maintenance and testing interval assigned (list the testing required at 2, 4 and 6 years). This same interval should apply to all areas in the table. • Life span of PC’s, software and software license’s are much less than 12 years or asset life. This presents a problem during an audit where proof is required. The components in modern relays have not been proven over these extended time periods, users are dependent on proper functions of the alarm output of IED’s. Prefer more frequent maintenance cycles over having to continuously document proof of a robust CBM or PBM program. • The burden placed to provide proof of compliance with a CBM or PBM maintenance program seems to outweigh any benefit in maintenance costs or reliability.
Individual
John E. Emrich
Indianapolis Power & Light Co.
Yes
 
No
Many preventive maintenance programs have testing tolerances which are tighter than the manufacturer’s tolerances. This practice is used to force an action prior to falling outside of the manufacture’s tolerances and accounts for slight variations in test equipment and environment. Maintenance correctable issues should not be reportable unless the test failure falls outside of the manufacturer’s published tolerances. In tables 1a through 1c the “Type of Component” columns in each table do not have consistent listings from one 1a to 1b to 1c. The type of component should be identified consistently in each table. By doing so this would eliminate confusion in moving from one table to the other. The maintenance activities for some types of components specifies how (ie Test and calibrate the relays….with simulated electrical inputs) while other maintenance activities do not specify how. The maintenance activities should either all be specific or all be generic. For Station dc Supply (that has as a component any type of battery) the maintenance activity of “verify that no dc supply grounds are present” there is a problem of tolerance. It is impossible to have “no dc supply grounds present”. There has to be some tolerance given here such as a voltage measurement form each battery terminal to ground +- 15 volts of nominal for example. For the type of component of “Protection System Control Circuitry (trip circuits) (UFLS/UVLS Systems only), the maintenance activity requires a complete functional trip test….of the Protection System. This suggests that a breaker trip test is required at each maintenance interval. This requires tripping breakers that supply customers. It is impossible to trip each individual distribution feeder without forcing an outage on some customers as when there are no other usable circuits to tie the load off to. A failure to trip of a single distribution circuit in the overall scheme of a UVLS or UFLS scheme would have little effect on the BES. Trip testing BES breakers and verifying correct operation of breaker auxiliary contacts could become very difficult to accomplish since opening a breaker on a line might adversely affect the BES. ISOs may prohibit such an activity at any time. Allowances should be made for BES circuit breakers that can not be operated for such reasons if documented sufficiently.
No
See comments in number 2 above.
Yes
 
No
Establishing historical performance and keeping the documentation up to date makes this almost useless
No
 
No
 
Performing some of the maintenance activities may cause conflict with regional ISOs and their safe operation of the BES
 
 
Individual
Glenn Hargrave
CPS Energy
Yes
 
No
While I agree for the most part, there are some activities that are unclear. Specifically, the testing of voltage and current sensing devices, some of the trip coil testing, and some of the communications testing. If the trip coil is now going to be included in the definition of the protective system, is the testing defined adequate? The testing of the voltage and current sensing devices is not entirely clear.
No
The first problem that I have is the 3 Months for the Protection system communications equipment and channels component. My main concern with this interval is that it is so extremely short and I am concerned that there may not be any rational behind it. What studies, surveys, or statistical data were used to determine that 3 months is necessary to protect the reliability of the BES? It doesn't make sense that a communications signal needs to be checked every 3 months but the protective relay that utilizes that scheme needs to be checked at most only every 6 years. What concerns me the most with the 3 month interval for my company is with on-off power line carrier DCB schemes. We only have these schemes on tie lines, and it can be difficult to implement a checkback system with another utility who might utilize different carrier equipment. This type of scheme is also intended to be inheritantly insecure and is frequently more or less tested with faults in the system. The SPCTF should do surveys to determine what is presently done with these type of systems or provide some other rationale for the communication requirements. It is not totally clear from the documents, but it appears that the only way to avoid the 3 month check for an on-off power-line carried DCB scheme is to have an automated check back scheme. Is this correct? Or is alarming from the carrier equipment adequate? My second problem is with the 6 year maximum maintenance interval for the breaker trip coil in tables 1b and 1c. By having to verify that each breaker trip coil is electrically operated, you might as well perform a functional test to test the protection system control circuitry. Electrically operating the trip coil tests the breaker as much as it test the actual trip coil. Also, if you have a primary and secondary trip coil, is it really necessary to test this often? What studies or statistical data were used to determine that testing the breaker trip coils every 6 years is necessary to protect the reliability of the BES? My third problem is with the intervals requirements for the UVLS/UFLS systems. Other than testing and calibration of electromechanical UVLS/UFLS, most other tests probably should require at most 10 years for these type of systems. These systems don't require the performance level of most other systems as stated in the supplementary reference. The testing and calibration of electromechanical UFLS should possibly be even shorter than the 6 year requirement due to problems with drift with these type of relays. What studies, surveys, or statistical data were used to determine the intervals in related to UFLS/UVLS.?
Yes
 
Yes
 
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe things a little differently.
Yes
Adds to the confusion with the standard, FAQ, and Supplemental. The three documents at times describe things a little differently.
 
 
Have several comments and questions: 1. I think that the way that the tables are done is confusing. My biggest complaint is that the "breakdown" of the Type of Component varies between the tables. For example, in tables 1a and 1B, you have Protective Relays, but in table 1c, you have Protective Relays and Protective Relays with trip contacts. This is a little confusing at times. 2. I also find the UFLS/UVLS requirments confusing as well. It can be confusing to figure out when the UFLS/UVLS has a separate requirement. Would prefer to see the UVLS/UFLS in separate tables; e.g. 2a, 2b, 2c. 3. SPCTF should provide the basis for how the intervals in table 1 were derived. While the supplemental describes that a survey of its members with a weighted average was used to determine the maintenance intervals. However, what is not clear is what exactly was surveyed in terms of components. Was it just relay calibration testing? Functional testing? What about communications, voltage and current sensing devices, trip coils, etc? Was UVLS and UFLS looked at separately from transmission? Was generation also considered as well? Why did values change from the SPCTF technical reference "Relay Maintenance Technical Reference" dated September 13, 2007. For example, UVLS/UFLS testing and calibration went from 10 years to 6 years for un-monitored, communications went from 6 months to 3 months for un-monitored, and instrument transformer testing went from 7 years to 12 years for un-monitored systems. What are the basis for the intervals? 4. The committee should reconsider the use of the term "A/D converters". The point of the requirement is to assure that the analog signal from the instrument transformer is correct to the processor. Two problems with just saying "A/D converters". One, it ignores the digital relay input transformers of microprocessor relays. The SEL-4000 test set can bypass these transformers. Would using this test set be adequate to test the "A/D converters"? Two, some relays, such as the SEL-311L, perform an A/D self-test. I do not think that the A/D self-test performs the testing that is being sought by the document. 5. Could a better example of "Calendar Year" be provided? Is it simply the years difference, or should the days be included as well? I your example in the reference document, you show that December 15, 2008 and December 31, 2014 as meeting the requirement of 6 calendar years. Woudl like to see a more exaggerated example. Would an unmonitored protective relay is calibrated on January 1, 2008 and then again on December 31, 2014 meet the "Maximum Maintenance Interval" of "6 Calendar Years"? 6. Does the standard address breakers and other switching devices that do not have "trip coils". Magnetic actuated circuit breakers, reclosers, and possibly other devices do not have trip coils to monitor or test. Do the trip coil testing and requirements fully take this account? If a breaker does not have a trip coil, is some other type of test required? Does not having a trip coil prevent extending the Protection System Control Circuitry inteval to 12 years? 7. The requirement for testing Voltage and Current Sensing devices should be better thought out as to what is trying to be accomplished. On page 11 of the reference document, item 6 under "Additional Notes for Table…", it states that "phase value and phase relationships are both equally important to prove". In both the FAQ document (page 6, 3A) and the reference document (page 21, 15.2), several methods to verify the voltage and current sensing inputs to the protective relays and satisfy the requirement are given. However, these methods do not all seem to verify the same thing. Totalizing watts and vars on the bus verifies that the current transformers are correctly and providing correct signals to the relays, but do not necessarily verify that the voltage sensing device is necessarily correct if the same PT is used for all relays on the bus. Performing a saturation test on a CT and a ratio test on the PT does not verify the phase angle relationships, which is stated as important on page 11 of the reference document. What exactly needs to be accomplished by the Voltage and Current Sensing devices testing? That an analog signal is getting from the instrument transformer to the device? That the signal is an accurate representation of the measured quantity? What about frequency for UFLS relays, where voltage magnitude may not be that important? Do CT's need to be verified for multiple CT grounds? Do the any examples described necessarily find multiple ct grounds? 8. This standard should also address the ramifications of RRO's not allowing for equipment to be removed from service for testing. Either RRO's should be required to allow outages in some time frame or leeway should be given to entities that cannot get equipment out for maintenance because RRO's will not grant reasonable outage times for testing and maintenance. 9. Page 13 of the reference document states that the 3-month inspection should include checking that "equipment is free of alarms, check any metered signal levels, and that power is still applied." What is meant by "metered signal levels"? What does the term "metered" mean, specifically in terms of an on-off power line carrier scheme. 10. It appears that if a company on a TBM plan has shorter intervals than the maximum allowable of this proposed standard, the company would not be in violation if they did not meet their own plan but still met the intervals required by this proposed standard. Is this true? Could this actually reduce reliability of the BES if companies are now allowed to extend intervals to those listed in this document without any justification?
Individual
Darryl Curtis
Oncor Electric Delivery
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
The “Supplementary Reference Document” provides good technical justification for the various approaches to a maintenance program (Time Based, Performance Based, and Condition Based) or combinations of these programs that an owner of a Protection System can follow.
Yes
The FAQ document is an excellent resource document for Protection System Owners to understand why the maintenance activities listed in the proposed standard were chosen.
 
 
The drafting team is to be commended for taking the Technical Paper and Draft Standard that was prepared by the NERC System Protection and Control Taskforce (SPCTF) and the recommendations of the SAR drafting team to create PRC-005-2. This draft standard allows the owners of Protection Systems several options in establishing a maintenance program tailored to their equipment and the topography of their system.
Group
PacifiCorp
Sandra Shaffer
Yes
 
No
No comment.
No
No comment.
Yes
 
Yes
 
No
Very helpful.
No
Very helpful.
None known.
None known.
What is the definiton of "Calendar Year"? Does the term "Six calendar years" include any date in 2004 to any date in 2010?
Individual
Armin Klusman
CenterPoint Energy
 
No
a. CenterPoint Energy believes the approach taken by the SDT is overly prescriptive and too complex to be practically implemented. The inflexible minimum “maintenance activities” approach fails to recognize the harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program based on their configurations and operating experience. In particular, the loss of maintenance flexibility embodied in this approach would have perverse consequences for entities with redundant systems. Entities with redundant systems have less need for maintenance of individual components (due to redundancy) yet have twice the maintenance requirements under the minimum “maintenance activities” approach. For example, Table 1A calls for performing a specific gravity test on “each cell’ of vented lead-acid batteries. CenterPoint Energy believes such a requirement is dubious for entities that do not have redundant batteries, and absurd for entities that do. CenterPoint Energy has installed redundant batteries in most locations and has had an excellent operating history with batteries by using a combination of internal resistance testing and specific gravity testing of a single “pilot cell”. This practice, combined with DC system alarming capability, has worked well. b. CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To clarify this last point, CenterPoint Energy is not asserting that maintenance problems do not exist. However, requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal, regardless of how existing practices are working, is not an appropriate solution. Among other things, requiring entities to modify practices that are working well to conform to the rigid requirements proposed herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements, degrade reliability performance. c. Arguably, an entity could possibly return to its existing practices, if those practices are working well, by navigating through the complex set of options and supporting documentation that the SDT has crafted in this proposal. However, most entities, have an army of substation technicians with various ranges of experience to perform maintenance on protection systems and other substation components. It is unrealistic to expect most entities making a good faith effort to comply with this proposal to have a full understanding throughout the entire organization of all the nuances crafted into this complex proposal. d. For the reasons outlined above, CenterPoint Energy does not agree with the proposal to specify minimum maintenance activities. However, if the majority of industry commenters agree with the SDT’s proposal, CenterPoint Energy has concerns about some of the proposed tasks. For Protection System control circuitry (trip circuits), Table 1A calls for performing a complete functional trip test. The “Frequently-asked Questions” document states that this “may be an overall test that verifies the operation of the entire trip scheme at once, or it may be several tests of the various portions that make up the entire trip scheme”. Such a requirement creates its own set of reliability risks, especially when monitoring already mitigates risks. CenterPoint Energy is concerned with this standard promoting an overall functional trip test for transmission protection systems. This type of testing can negatively impact reliability with the outages that are required and by exposing the electric system to incorrect tripping. CenterPoint Energy views overall functional trip testing as a commissioning task, not a preventive maintenance task. CenterPoint Energy performs such testing on new stations and whenever expansion or modification of existing stations dictates such testing. Overall, CenterPoint Energy recommends minimizing, to the extent possible, maintenance activities that disturb the protection system; that is, placing the protection system in an abnormal state in order to perform a test. e. For Protection System control circuitry (breaker trip coils only), Table 1A calls for verifying the continuity of the trip circuit every 3 months. CenterPoint Energy is not sure what would be the expected task to meet this requirement (it is not addressed in the “Frequently-asked Questions’ document).
No
a. See CenterPoint Energy’s comments made in response to question 2. Imposing inflexible maximum interval requirements has the same basic problems as imposing inflexible minimum task requirements. The inflexible “maximum interval” approach fails to recognize the harmful effects of over-maintenance and precludes the ability of entities to tailor their maintenance program based on their configurations and operating experience. The maximum interval approach also has same perverse consequences for entities with redundant systems as the minimum interval approach. b. Furthermore, the rigid maximum interval approach embodied herein does not sufficiently take into consideration common natural disaster situations. Several of the preventive maintenance tasks proposed in this standard have a maximum interval of 3 months, which is problematic under normal circumstances and unworkable when routine maintenance activities have a much lower priority than emergency repair and restoration. An interval as short as this does not provide a sufficient maintenance scheduling horizon to complete the tasks. The SDT could attempt to address this shortfall by modifying the draft to account for natural disaster situations. For example, the FERC-approved NERC reliability standard FAC-003 for Vegetation Management does include such allowances for natural disasters, such as tornados and hurricanes. However, even if that specific problem is addressed, the fundamental problems created by an overly prescriptive maximum interval approach remains.
 
No
a. CenterPoint Energy lauds the SDT for recognizing that strict imposition of the maximum interval approach creates problems which the SDT attempts to correct by allowing performance-based adjustments. CenterPoint Energy believes the majority of industry commenters will agree with CenterPoint Energy’s assessment that the maximum interval approach is problematic and should be dropped from the proposal. However, if the majority of industry commenters agree with the SDT’s approach, then a performance-based option to correct the problems introduced by the maximum interval requirements should remain. b. CenterPoint Energy answered “No” to question 5 because CenterPoint Energy believes the arduous path of creating a new set of problems with a rigid approach (maximum interval requirements) and then introducing a complex set of auditable requirements to provide an option (performance-based maintenance) to mitigate the harm of the rigid approach is ill-advised and fraught with pitfalls. Stated otherwise, using performance-based adjustments to correct inappropriate maximum intervals would not be necessary if the inappropriate maximum intervals were not imposed. CenterPoint Energy believes a better approach is to avoid introducing the new set of problems that then have to be mitigated by not imposing problematic maximum intervals. c. Followed to its logical conclusion, using performance-based adjustments to correct inappropriate maximum intervals is a contorted way of arriving at the philosophy embodied in the current set of standards in which entities determine the maximum intervals appropriate for their circumstances and performance. CenterPoint Energy’s concern is that the contortions needed to arrive at the same point, in addition to being unnecessary, will be difficult for most entities to navigate. An entity making a good faith effort to comply with the performance-based adjustments will have to navigate through the complexities and nuances of the approach, as illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the requirements and nuances. As an entity attempts to manage this hurdle, the entity will likely have to deal with the reality that the granularity of performance metrics do not exist in most cases to justify to an auditor the rationale for the adjustments to the inappropriate maximum intervals. For example, CenterPoint Energy has asserted that it has had good battery performance using existing practices. However, the assertion is anecdotal. CenterPoint Energy cannot recall any instances where it had a relay misoperation due to battery failure in over twenty five years. CenterPoint Energy does not attempt to keep performance metrics on events that historically occur less than four times a century and CenterPoint Energy believes most entities will be in the same situation. d. If an entity is somehow able to overcome these hurdles, the entity will almost certainly encounter skepticism for what will be viewed as an exception to the default requirement embodied in the standard. Even if an entity can overcome likely skepticism in an audit, the entity will be in a severely disadvantaged situation if a protection system component for which the maintenance interval has been adjusted, based on the entity’s good faith effort and reasoned judgment, nevertheless is a contributing factor in a major reliability event investigation, regardless of whether the maintenance interval adjustment contributed to the failure. No matter what maintenance intervals are used, protection system components could fail. If the maintenance interval has been adjusted and if failure occurs, it will likely be unknown whether the interval adjustment was in fact a contributing factor or whether the failure would have occurred anyway. e. Faced with this dilemma, in addition to all the other hurdles to overcome in attempting to adjust an inappropriate maximum interval, the reality is that most entities will accept the inappropriate maximum interval and over-maintain their protection system components, and introduce a new set of reliability risks from such over-maintenance. For these reasons, CenterPoint Energy advises against creating a new set of problem by imposing rigid maximum intervals and then attempting to correct the problems through a performance-based mechanism that in actual practice would likely be illusory.
Yes
CenterPoint Energy believes the need for an extensive “Supplementary Reference Document”, in addition to 13 pages of tables and an attachment in the standard itself, illustrates that the proposal is too prescriptive and complex for most entities to practically implement. CenterPoint Energy would prefer the SDT leave the existing requirements substantially intact or, if most industry commenters prefer the SDT’s approach, that the SDT attempt to simplify it.
Yes
See CenterPoint Energy’s response to question 6. The need for an FAQ document in addition to an extensive “Supplementary Reference Document” further illustrates the complexity and impracticality of the proposed standard revisions.
 
 
a. CenterPoint Energy believes the existing maintenance standards are preferable to the approach embodied in this proposal. However, if most entities agree with the SDT’s approach, CenterPoint Energy recommends deleting Under-Frequency Load Shedding (UFLS) and Under-Voltage Load Shedding (UVLS) system equipment from the scope of this proposal because the performance requirements for UVLS and UFLS are substantially different from transmission and generation protection schemes. Few would argue that protection schemes that clear faults on the Bulk Electric System must be very reliable, much more reliable than schemes that shed distribution load for under-voltage or under-frequency situations. If an entity plans to shed a contemplated level of load for a contemplated set of circumstances based upon planning simulations, that plan would translate into a certain number of distribution feeders that are reasonably predicted to shed a load amount that is reasonably close, but not exactly equal (unless by chance) to the contemplated amount of load shed. For example, if a certain number of distribution circuits equals 10% of the entity’s load during one time (such as system peak), that same amount of distribution circuits will almost certainly equal a different percentage of the entity’s load at other times. So, if hypothetically 100 distribution circuits are armed with UVLS or UFLS relays set a given trip point, the actual percentage of load that will be shed will vary under different system conditions. Therefore, if 95 of the distribution circuits actually trip on one occasion and 98 trip on another occasion, the difference in system performance is immaterial because the exercise is not that precise, especially when planning simulation uncertainties are also introduced into the picture. For these reasons, CenterPoint Energy believes it is unreasonable to impose a high level of rigidity into load shedding schemes when the designs of the schemes inherently do not depend on such rigidity. If the SDT agrees, then the revised standard would not be applicable to Distribution Providers, and 4.1.3 can be deleted. b. CenterPoint Energy also disagrees with the proposed expansion of the Protection System definition. The present definition does not include trip coils; and correctly so, as trip coils are part of the circuit breaker. A protection system has correctly performed its function if it provides tripping voltage up to the breaker’s trip coils. From that point, the breaker can fail to timely interrupt fault current due to several factors such as a binding mechanism that affects breaker clearing time, a broken pull rod, a bad insulating medium, or bad trip coils. Local breaker failure protection is installed to address the various possible causes of circuit breaker failure. Planning standard TPL-001 tables 1C and 1D specifically support the present definition, as Delayed Clearing is noted as due to “stuck breaker or protection system failure”.
Individual
Howard Gugel
Progress Energy
Yes
 
No
Progress Energy does not agree with the activity “Verify that the battery charger can perform as designed by testing that the charger will provide full rated current and will properly current-limit.” We are unclear how this test should be performed.
No
The rational for microprocessor-based relay intervals is examined, but all others are strictly based on industry weighted average of survey results. We believe the team should use a more empirical, documented approach to determining these intervals, as many companies have longer intervals that they currently have documented for their basis. If these have been accepted as satisfactory in previous audits, why should they be required to change just to meet an arbitrary number?
 
 
Yes
Progress Energy is concerned that separating this document from the standard may lead to issues down the road. If the desire is to consolidate and clarify existing standards, then the two documents should be merged. Otherwise the reference document may get lost from the standard, or might get changed without due process, or might not even be recognized by FERC.
Yes
Progress Energy is unclear how a new/revised standard can have a 30 page FAQ document associated with it. If questions need to be addressed, the answers should be incorporated into the existing standard. During this stage of the draft, all questions should be addressed, not left to the side in an “interpretation” paper.
 
 
Comments: 1- Requirement R4 “Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, including identification of the resolution of all maintenance correctible issues as follows: “ Based on the definition provided (A maintenance correctable issue is a failure of a device to operate within design parameters that can be restored to functional order by calibration, repair or replacement.) Pr ogress Energy believes that this will become a potential tracking issue. To maintain all of the data required to meet this definition can be onerous. 2- The biggest concern with the proposed PRC is that for many entities, the proposed maintenance and intervals will greatly increase the entities’ workloads. There are not enough relay technicians available to handle this increased workload across the country. 3- The Implementation Plan for R2, R3, and R4 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is very reasonable. This plan recognizes that it is unrealistic to expect entities that are presently using intervals that exceed the maximum allowable intervals to immediately be in compliance with the new intervals. It allows implementation to be implemented across the maximum allowable interval. This is a reasonable approach for the following reasons: a. Sufficient resources are not available to perform the additional maintenance proposed on an accelerated basis. b. It allows the staggering of the PMs so that resource loading can be balanced. Without the ability to stagger the PMs, there would be an initial “bow-wave” of PMs and future “bow-waves” each time the interval is up. 4- The Implementation Plan for R1 identified in the Draft Implementation Plan for PRC-005-02, dated July 21, 2009, is not reasonable. The implementation plan requires entities to be 100% compliant three months following approval of the PRC. This is not a reasonable timeframe given the program changes required, including: a. A massive effort to review circuit schematics to determine whether equipment meets the definition of partial-monitored or unmonitored. b. Many procedures, basis documents, and job plans will need to be revised or created. c. The work management tool will have to be modified to reflect the new intervals. 5- PRC-008-1 placed only the relays associated with UFLS in the compliance program. Contrary to PRC-008-1, the draft PRC-005-02 places all components (relays, instrument transformers, dc supply, breaker trip paths) in the compliance program. This forces much of the distribution-level components to be placed in the compliance program. 6- The response to Item 2A of the FAQ Document, page 17, seems to indicate that commissioning test results do not have to be captured as the initial test record, only the in-service date. Is this a correct interpretation of the response? 7- Table 1a (Unmonitored Protection Systems) seems to indicate that a complete functional trip test must be performed for the UFLS/UVLS protection system control circuitry. This wording is identical with the wording for the protection system control circuitry (except UFLS/UVLS) table entry. This implies that UFLS/UVLS functional testing should include tripping of the feeder breakers for these unmonitored systems. Table 1b (Partially-Monitored Protection Systems) indicates that actual tripping of circuit breakers is not required under the UFLS/UVLS control circuit functional testing. Is this because trip coil continuity is being monitored and alarmed under Level 2 Monitoring? Must feeder breakers be tripped during the functional testing if the trip coil continuity is not monitored and alarmed (unmonitored protection system)? 8- All standards to be retired should be specifically listed in the Implementation Plan.
Individual
John Moraski
BGE
 
 
 
 
 
 
 
 
 
PRC-005-2 R1 1.2 “Identify whether each Protection System component is addressed through time-based, condition-based, performance-based, or a combination of these maintenance methods and identify the associated maintenance interval.” Comment: The existing standard PRC-005-1 requirement R1.1 says a maintenance program must include the maintenance and testing intervals and their basis. PRC-005-2 does not have a similar requirement, and the associated FAQ indicates the standard “establishes the time-basis for a Protection System Maintenance Program to a level of detail not previously required”. Does PRC-005-2 require evidence to support the basis for a defined maintenance interval, or is the basis now purely defined by PRC-005-2? R2 “ Each transmission owner .......shall ensure the components to which condition-based criteria are applied....possess the necessary monitoring attributes” Comment: Depending on the evidence requirements that are enforced this could be a very large undertaking offsetting the benefit of extending intervals with CBM. It would be helpful to understand what the drafting team or other stakeholders would envision as appropriate evidence supporting this requirement. R4 “Each transmission owner .......shall implement its PSMP, including the identification of the resolution of all maintenance correctable issues as follows : 4.1 ....within the maximum allowable intervals not to exceed those established in table 1a, 1b, 1c Comment: It’s inferred that this requirement applies to maintenance correctable issues that are discovered as a consequence of scheduled maintenance and not as a consequence of monitoring or misoperations. If that inference is incorrect the requirement imposes an unequal playing field for the resolution of known correctable issues depending on the monitoring being employed, not to mention an unreasonably long allowance for the correction of some serious problems. On the other hand, the requirement imposes an unreasonably short period of time for the resolution of some issues that may be associated with short interval maintenance/inspection intervals, such as battery grounds. Section D 1.4 Data Retention “The Transmission Owner..shall...retain documentation for two maintenance intervals....” Comment: Recognizing that in order to achieve compliance PS owners will execute scheduled maintenance on shorter intervals than the maximum requirement it’s uncertain what this means. Example: Max interval for instrument transformers is 12 years, we maintain every six. Is the requirement for 24 years of data or 12. It seems like there ought to be an upper limit. 24 years is a very long time. Table 1a Protection System Control Circuitry (Breaker trip coil only) ; 3 month maximum interval ; “verify the continuity....of the trip circuit .....except for breakers that remain open for the entire maintenance interval.” Comments: What’s the failure-probability justification for this requirement when other similar dc control components have a maximum interval of 6 years? It seems like the SDT made an assumption that all trip coils are monitored by red lights and could be verified by inspection and said somewhat arbitrarily, “do it because you can”. “Remaining open for the entire maintenance interval” is a poorly reasoned effort to arrive at a necessary exception. Even if the red-light-through-the-trip-coil assumption is accurate for a normally open breaker, it’s unreasonable to demand that an inspection take place if its closed at anytime during the interval. The actual time that its closed might be seconds or a few minutes, but that time would make the exception moot and put the owner out of compliance. On the subject of three month maximum intervals in general: One can agree that three months is about the right time for some of these inspections, batteries in particular. However as written, three months and a day is “out of compliance”. More flexibility would avoid a lot of meaningless “technical fouls”. How about four times a year not more than four months between each...or something like that. Table 1a Station DC supply (that has as a component any type of battery); “verify that no dc supply grounds are present” Comment: All grounds are not created equal. No guidance for acceptance criteria is given, nor is evaluation/acceptance criteria explicitly made the responsibility of the battery owner (as it is for relay calibration) . Without any guidance the requirement of “no” grounds is open to unreasonable interpretation (there is always a ground if one considers a high enough resistance) and high impedance grounds that do not present a risk to the PS will consume effort and attention unnecessarily. Station DC supply (that has as a component any type of battery); “Measure the specific gravity and temperature of each cell is within tolerance” Comment: It is not clear that a specific gravity test provides any better data concerning battery health than an impedance test, but specific gravity testing is a requirement. Can the impedance test be performed as routine maintenance in lieu of a specific gravity test? General Comment: It is not clear whether Communications batteries should be held to the same testing/maintenance requirements as the station battery. Communications batteries are in place to supply relatively low power electronic equipment and do not have to provide energy to trip a breaker. Simple monitoring of the channel may be sufficient to assure battery availability, and a less rigorous maintenance plan may be appropriate based on the continuous monitoring and low duty of the battery. FAQ Group by Monitoring Level A level 2 (partially) monitored Protection System or an individual component of a level 2 monitored Protection System has monitoring and Alarm circuits on the Protection System components. The alarm circuits must alert a 24-hour staffed operations center. Comment: The Standard Table 1b, General Description for Level 2 monitoring is simply described as Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for alarmed features. This appears to be a conflict between the FAQ and the standard. The more stringent requirement of the FAQ, for the reporting facility to be manned 24 hours per day, could be read to imply a requirement for a specific time to respond to an alarm. Is there such a requirement? Is there an implied requirement to document the alarm condition and the response time?
Individual
Dale Fredrickson
Wisconsin Electric
Yes
 
No
1. Page 7 Station DC Supply (Batteries): The activity to verify proper electrolyte level should only apply to unstaffed (unmanned) stations; checking battery electrolyte levels is routinely done in generating stations, which are staffed with personnel continuously (24 x 7). In addition, the three activities listed here with a 3 month interval for batteries (electrolyte, voltage, grounds)should NOT require documentation for compliance purposes. It should be sufficient that these routine and recurring activities (every 3 months) are identified in the Maintenance Plan. Otherwise the administrative burden to provide documentation will become excessive and counterproductive to assuring BES reliability. 2. Page 7 Station DC Supply (Batteries): The 18 month interval includes an activity to verify the battery charger equalize voltage. This activity is normally done only when the bank is load tested. Therefore the activity to verify equalize voltage of a charger should have a 6 year interval along with the other battery charger activities to verify full rated current and current-limiting. 3. Page 9 Communications Equipment: Similar to #1 above, the activity to verify monitoring and alarms should NOT require documentation in order to demonstrate compliance. Having these routine 3 month activities in the Maintenance Plan is sufficient. This needs to be clarified in the standard. Also, this requirement should be re-worded to refer to generating stations also, not just substations. 4. Page 11 Station DC Supply (Batteries): Like #1 above, the similar requirement in Table 1b for verifying battery electrolyte levels should be revised to indicate that documentation is NOT required. 5. Page 6 Prot System Control Circuitry: Like #1 above, the 3 month activity to verify continuity of breaker trip circuits is fine, but there should be no requirement to document the readings or observations; it is sufficient that this activity be addressed in the Maintenance Plan, especially for staffed generating stations. 6. Page 6 Prot System Control Circuitry: For the 6 year activity to "perform a functional trip test...": is this a requirement to actually trip the circuit breaker ? If yes, this should be stated clearly in the Maintenance Activity description. 7. We are concerned that the Maintenance Activities are not appropriate for certain equipment. The RFC definition of Bulk Electric System includes any protection equipment that can trip a BES facility independent of voltage level. As an LSE, this includes distribution-level equipment that was not designed to the same level of redundancy as Transmission equipment. Complying with the requirements for control circuitry functional testing and current sensing device testing will actually decrease system reliability since this often cannot be accomplished without requiring outages to major distribution system components and/or temporarily breaking protection circuits. We propose that this type of testing on distribution systems which fall under the definition of BES Protection Systems should be addressed separately from the rest of the BES Protection Systems in this standard. The intervals and/or maintenance activities should reflect the differences in how these distribution protection systems are designed and operated.
No
Similar to comments in #7 above: It is our practice on distribution-level protection systems to utilize a 6 year interval plus/minus 1 year to accomodate potential scheduling conflicts. This is consistent with other LSE's relay testing practices as well. Thus the potential 7 year maintenance interval would be a violation of the draft requirements. The maintenance intervals in this standard should be increased accordingly for distribution protection system equipment.
Yes
 
Yes
 
Yes
How much authority or weight will this document have with Compliance staff? If potential violations of the standard requirements are alleged by Compliance staff, can this document be cited by an entity when the document provides clarifying information on the requirements ?
No
 
 
Regional Variance
See above Question 2, Item 7: There needs to be some recognition that Protection System's applied on distribution-voltage systems may be included in a regional definition of a BES Protection System. These systems are not designed or operated in the same way as Transmission or Generation Protection Systems. Therefore, it is reasonable that these systems be subject to less rigorous requirements.
1. In the definition of a Protection System Maintenance Program, the statement is made that "A maintenance program CAN include...", with a list of seven attributes following. Is it the intent that the PSMP "SHALL include one or more of the following" ? What is to prevent Compliance staff from concluding that all seven of these attributes MUST be included in the PSMP ? 2. The standard should more clearly describe what is meant by "verify..." when used in a Maintenance Activity description. Does this require actual paper or electronic documentation? If so, then this should be explicitly stated in the Maintenance Activity description. We maintain above that the recurring and routine maintenance activities having a 3 month interval should be revised to use alternate words such as "Check" or "Observe". For example, "Check the continuity of the breaker trip circuit...", or "Observe the voltage of the station battery". This activity should not be required to have paper or electronic documentation or evidence. It should be sufficient to have these activities included in the PSMP. 3. It is stated in the Supplementary Reference that actual event data from fault records may be used to satisfy certain Maintenance Activities, yet the standard itself does not appear to allow for this. Will such evidence be accepted by Compliance staff?
Group
Florida Municipal Power Agency, and its Member Cities as follows: New Smyrna Beach; City of Vero Beach; and Lakeland Electric
Frank Gaffney
Yes
 
No
FMPA does not believe that maintenance of each UFLS / UFLS systems are as important as maintenance of BES protection systems. The fundamental reason is that delayed or uncleared faults on the BES can cause system “instability, uncontrolled separation, and cascading outages”; therefore, BES protection systems are very important; however, if a small percentage of UFLS / UVLS relays mis-operate as a result of a frequency or voltage event, the impact of the mis-operation is much smaller, if even measurable. As a result, FMPA believes that the emphasis of the maintenance activities ought to be placed on those systems that can have the most impact on what the standards are all about, as Section 215(a)(4) of the Federal Power Act says, “avoiding instability, uncontrolled separation, and cascading outages”. As a result, FMPA believes that full functional testing, while important for BES protection systems, is not necessary for UFLS and UVLS systems (Table 1a, page 6 and Table 1b, page 11). Because most UFLS / UVLS are on radial distribution feeders, such testing will cause outages to customers fed on radial distribution circuits and transmission lines without sufficient cause, in other words, the maintenance itself will reduce the reliability the customer experiences. In addition, distribution tripping circuits are more regularly exercised by distribution faults than are transmission tripping circuits; therefore, full functional testing of distribution tripping circuits is far less valuable than testing trip circuits of transmission elements which are exercised less frequently due to actual system events. FMPA is confused with the wording of Table 1a, page 6, row 3 that talks about breaker trip coils. In the “Type of Component” column, the subject says “Breaker Trip Coils Only (except for UFLS or UVLS)”, yet the maintenance activity described states “Verify the continuity of the breaker trip circuit including trip coil”. These two statements are inconsistent because the first statement limits the applicability to just the trip coil and the second statement goes beyond the trip coil. And, FMPA believes the second statement should only apply to the trip coil, e.g., the second statement should say: “Verify the continuity of the trip coil”. In addition, the parenthetical is confusing, is it meant to say that the continuity of the trip coil only needs to be verified when the breaker operates during the 3 month interval, or that the intended continuity check is from the relay contacts through the trip coil, and not from the relay contacts back to the batteries? FMPA is also confused concerning station DC supply testing. There are multiple rows in Table 1a concerning various types of testing for various types of batteries and chargers that do not exclude UVLS and UFLS, yet on page 8, on the bottom row, the row is exclusive to UVLS and UFLS yet overlaps other rows discussing station DC supply testing. Is it intended that the other rows that are silent as to what they apply to exclude UVLS and UFLS? FMPA believes that should be the case. The same comment applies to Table 1b. FMPA also has concern over the battery charger testing requirements. Per the charger manufacturers recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion that the chargers are self diagnostic and do not require these tests (full load current and current limiting tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore, FMPA takes exception to this requirement and suggests that battery chargers be maintained and tested in accordance with manufacturer’s recommendations
No
FMPA agrees in general with many of the maximum maintenance intervals; however we have been unable to determine what basis was used to arrive at the time based intervals provided in the tables. Further explanation would be appreciated FMPA is concerned with the use of the term “continuous” in Table 1c. As stated, it would seem that, on loss of communications that would communicate the alarm, thereby causing a loss of “continuous” monitoring and alarming, the entity who invested in a reliability improving monitoring system would be found non-compliant with an infinitesimal maintenance period required for “continuous” monitoring. Therefore, FMPA recommends using “not applicable” or some other term in this column.
Yes
FMPA agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the use of the word “every” in table 1c in “Protection System components in which every function required for correct operation of that component is continuously monitored and verified” may be overstating the level of monitoring that would realistically enable a Protection System to use table 1c.
No
FMPA believes that the documented process outlined in Attachment A; "Criteria for Performance Based Protection System Maintenance Program" is biased towards larger entities. The requirement that the minimum population of 60 individual components of a particular segment is required to make a component applicable to this program automatically eliminates most of the small or medium sized entities. Further the need to first test a minimum of 30 indivudual components in any segment reinforces the same size limitation. FMPA suggests that the Performance-Based Protection System Maintenance Program allow for regional shared databases applicable towards meeting the establishment and testing criteria of similar individual components. This practice will allow for the inclusion of entities of all sizes. This will also provide a greater format for the discussion of lessons learned and improvements to the testing database on a regional basis.
No
 
No
 
FMPA is not aware of any conflicts
FMPA is not aware of a need for a regional variance
Facilities applicability 4.2.2, due to the changes in applicability of the draft PRC-006, ought to refer say something like UFLS which are installed per requirements of PRC-006 rather than per ERO requirements. In requirement R1, bullet 1.1 ought to state “For each component used in each Protection System, include all “applicable” maintenance activities specified in Tables 1a, 1b and 1c”. For instance, if every component has continuous monitoring, why should the program include 1a and 1b?
Individual
Russell C Hardison
TVA
Yes
 
Yes
Add clarifying statement from Table 1b for Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) to the same section in Table 1a. Statement is “(Verification does not require actual tripping of circuit breakers or interrupting devices.)"
Yes
 
Yes
 
Yes
Should allow inclusion of dc systems as well.
No
 
No
 
 
Business Practice
Allow for deferals to coordinate with generator outages.
 
Individual
Kirit Shah
Ameren
Yes
We commend the SDT for developing such a clear and well documented first draft. It generally provides a well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum intervals. Our existing M&T Program has and continues to yield a very reliable BES with mostly similar intervals, though some are longer and others shorter. We strongly support the almost all of the applicability revision, which clarifies the boundary of NERC maintenance and testing oversight. We question the addition of UFLS station DC Supply, auxiliary relays, and Generating facility system-connected station service transformers. Have these components been a significant source of problems leading to cascading outages? The SDT also modifies the Protection System definition, mostly clarifying the boundaries. We generally agree except that we recommend adding “fault” before “interrupting devices”.
No
We agree with the vast majority of them, listed below are our few concerns, questions, and pleas for clarification. 1) We disagree with doing specific gravity and temperature of every cell in the 18 month test because the other tests being done are already comprehensive. 2) FAQ 3B p 29 digital relay A/D verification should include simply comparing digital relay displayed metered values to another metered source. 3) FAQ 3A p6 Change “prove that” to “verify”. For single CT or VT, this can be challenging and some measure of reasonableness in determining an expected value comparable to the measured value must be acceptable. 4) FAQ 1B p17 Combining evidence forms of “Process documentation or plans” and “Data” or “screen shots” shows compliance. Please add an example or verbiage to clarify that a field technician’s (or operator) recorded check-off combined with a company’s process is sufficient evidence. Otherwise documentation alone could consume considerable field personnel time. 5) FAQ p2 Add FAQ to clarify “verify settings”. If EM relays are included, explain that minor tap or time dial differences of the order of relay tolerances are acceptable. For digital relays state that software compare functions are a sufficient means to “verify settings.” 6) Omit Table 1b row 3 because row 4 actually applies to Monitoring Level 2 Trip Circuits. Row 3 already appears in Table 1a, and repeating it in Table 1b is confusing. 7) FAQ 4D p 7 then defines auxiliary relays as device 86 and 94. Does device number nomenclature or function determine and restrict inclusion? 8) Please state that “a location where action can be taken for alarmed failures” would include a dispatch center or control room. From there the custodial authority would be called out to take action. 9) Please explain the expansion from station battery to station DC supply, specifically the addition of the charger, an AC to DC device. The charger load test up to its current limiter would add a significant amount of work with little known benefit. Have charger problems been a significant cause of cascading outages? 10) We oppose your expansion of Station DC Supply to UFLS (the last row on page 8.) PRC-008-0 is restricted to UFLS equipment. UFLS is often applied in distribution substations to trip feeders directly serving load. Your scope expansion has the potential to greatly increase the number of substation DC Supplies covered by NERC standards. ,. While we agree that UFLS is BES applicable, and those substations are included in our overall maintenance program, this expansion to NERC scrutiny is not warranted. Have there been UF events in which a material amount of load was not shed because of DC problems? UFLS is spread out amongst many distribution stations, and even if a couple did fail to trip in an underfrequency event, it would have little effect. 11) FAQ 2 p 17 expands the scope at Generating Facilities so that system connected station auxiliary transformers would be included. We oppose this expansion as these are radially served loads, and they often do not result in generation loss. Even if they did, the BES can readily tolerate the loss of a single generator.
No
1) The “zero tolerance” structure proposed combined with the large volume and complexity of Protection System components forces an entity to shorten their intervals well below maximum. We instead propose a calendar increment grace period in which a small percentage of carryover components would be tracked and addressed. For example, up to 10% of all breaker trip coils subject to the 3 month “verify breaker trip coil continuity” could carry over into the first month of the next period. And for example, up to 5% of an entity’s communication channel 6 year verifications could carryover into the next year. These carryover components would be addressed with high priority in that next calendar increment. There are many barriers to 100% completion or zero tolerance. Barriers include sheer volume, obtaining outages, resource availability, coordination, and documentation (over ten thousand components in our utility alone; taking a BES outage to permit maintenance can incur a greater reliability risk than delaying the maintenance; emergent issues such as major storms impact resource availability; coordination with interconnected neighbors, their resources and maintenance timing; record keeping errors or oversights; etc. ) 2) Alternatively, components with intervals less than a year should be stated in terms of the number of times annually it should be performed, rather than a short duration interval. The expectation is that they would be roughly equally spaced throughout the year; for example quarterly instead of 3 months. Comment 1 grace period would still apply to components with maximum intervals of 1 year or greater. 3) Some of our maintenance intervals are shorter than maximum. Please confirm that documentation is only to be kept for two of the entity’s intervals, not two of the maximum interval. 4) Please add standard language or FAQ near 2D on p 18 that an entity can validly use an interval with % tolerance to achieve maintenance goals, as long as the applicable maximum interval is honored.
Yes
We agree with the condition-based approach. Our comments in 3 above apply to Tables 1b and 1c as well. We note that Table 1b Station dc supply intervals are the same as Table 1a. Why doesn’t the monitoring cause 1b intervals to be longer than 1a?
Yes
While we agree with the approach, batteries should be allowed, not excluded.
Yes
1) We disagree with the page 22 statement that batteries cannot be a unique population segment of a PBM. 2) What role does the Supplement play in Compliance Monitoring and Enforcement?
Yes
1) We don’t think an Executive Summary is needed. 2) Please include the Supplement’s explanation of A/D verification method from Supplement page 9. 3) What role does the FAQ play in Compliance Monitoring and Enforcement? 4) Refer to question 2 and add our items # 2, 3, 4, 5, 7, and 11 to FAQ. 5) Please add FAQ that provides the NERC Compliance Reqistry Criteria for Generating Facilities, to clarify applicability to >20MVA direct BES connection, aggregate >75MVA etc. 6) FAQ 2A p17 states that commissioning is construction, not maintenance. It seems like you’re ignoring the significant verification, testing, inspection, and calibration activities that occur in commissioning. Should the in-service date be assigned to these components for determining their next maintenance? 7) Refer to question 3 and add our items # 4 to FAQ.
 
 
1) Documentation could be a monumental task. Although FAQ 1B allows a comprehensive set of forms of documentation, a very large number of people are involved across this set at most utilities. Producing a particular needle in the haystack may take longer than an auditor would expect. Inspection forms can be structured to capture abnormal conditions, and thus normal conditions are not recorded. Some items, like the red light monitoring a trip coil, may only be reported by exception (i.e., “red light out, replaced bulb” but if the red light is on an operator may not report that). 2) We presume that the SDT would expect transmission facilities to be switched out of service if maintenance would result in those facilities being unprotected. We think this should be stated or clarified, as there may be entities that still use differential cutoff switches or other means of disabling protection for testing and have not considered the consequences of a concurrent fault.
Individual
Huntis Dittmar
Lower Colorado River Authority
Yes
 
No
We agree with all stated intervals except for the maximum stated interval of 6 years for Protection System Control Circuitry (Trip Coils and Auxiliary Relays) in tables 1b and 1c. What was the intent of separating this interval out from the Protection System Control Circuitry (Trip Circuits), which is 12 years for monitored components? Monitoring of the trip coils should be enough to justify a maximum interval of 12 years. As stated these requirements will put an undue financial and resource burden on utilities that have updated their protective relay systems with state-of –the art components and monitoring. In addition to the expense and effort of scheduling the additional maintenance, the additional validation of lockouts and auxiliary relays, separate from the full function testing could lead to additional human errors and accidental tripping of circuits while testing. We believe there should be one stated activity “Protection System Control Circuitry and have a maximum interval of 12 years for monitored systems.
Yes
 
Yes
We commend the drafting team for recognizing the advantages of using monitored systems and a condition-based approach. This approach recognizes the benefits of using newer technologies and will give utilities added incentive to update their relay systems.
Yes
 
Yes
The Supplementary Reference is well written and helpful in explaining the drafting teams thought process.
Yes
The Frequently-asked Questions document is very well written and very helpful. The decision trees are a good addition.
Conflict: Potential conflict with PRC-023 as to which PRS systems are applicable per this standard. Comments:PRC-005-2 requires compliance for this standard for all non-radial systems over 100 kV; while, PRC-023-1 prescribes it as below: 1. Title: Transmission Relay Loadability 2. Number: PRC-023-1 3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with system operators’ ability to take remedial action to protect system reliability and; be set to reliably detect all fault conditions and protect the electrical network from these faults. 4. Applicability: 4.1. Transmission Owners with load-responsive phase protection systems as described in Attachment A, applied to facilities defined below: 4.1.1 Transmission lines operated at 200 kV and above. 4.1.2 Transmission lines operated at 100 kV to 200 kV as designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System. 4.1.3 Transformers with low voltage terminals connected at 200 kV and above. 4.1.4 Transformers with low voltage terminals connected at 100 kV to 200 kV as designated by the Planning Coordinator as critical to the reliability of the Bulk Electric System. 4.2. Generator Owners with load-responsive phase protection systems as described in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4. 4.3. Distribution Providers with load-responsive phase protection systems as described in Attachment A, applied according to facilities defined in 4.1.1 through 4.1.4., provided that those facilities have bi-directional flow capabilities. 4.4. Planning Coordinators. We believe Bulk Electric System (BES) owners’ resources would be better utilized by focusing on relay systems as defined in the above PRC-023-1 and this would still provide high level of reliability for the BES, since not all facilities operating between 100 – 200KV are critical to the BES. This would not preclude any utilities from applying this standard to other facilities operating at the lower voltage range. Why did the drafting team not use the application language sited in the “Protection System Maintenance - A NERC Technical Reference” which is similar to what is described above from PRC-023-1?
 
We commend the work done by the Standard Drafting team. In particular, the merging of previous standards PRC-005-0, PRC-008-0, PRC-011-0, and PRC-017-0 which will help with the efficient management of these standards.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
 
No
 
 
 
 
Group
Operations and Maintenance
Robert Casey
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
 
No
 
No conflicts known.
None.
None.
Group
Electric Market Policy
Jalal Babik
Yes
We commend the SDT for developing such a clear and well documented first draft. In general, it provides a well reasoned and balanced view of Protection System Maintenance.
Yes
 
No
Recommend that all Level 1 three-month maintenance intervals be changed to a quarterly based system where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to be scheduled every 2 months, which would result in six inspections per year. Our experience of four inspections per year has proven to be successful.
No
Recommend that all Level 2 three-month maintenance intervals be changed to a quarterly based system where only 4 inspections are required per year. Given a 3 month maximum interval, activities would need to be scheduled every 2 months, which would result in six inspections per year. Our experience of four inspections per year has proven to be successful.
Yes
 
No
 
No
 
None
Regional Variance
It is our understanding that once Project 2009-17: “Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State” is approved, that the definition of a “Transmission Protection System” would be included within PRC-005-2 or included within the NERC Glossary of Terms. However, the specific protection that would be considered part of the “Transmission Protection System” would also depend on the regional definition of the BES. We suggest that the regions develop a supplement that provides further clarification on what constitutes a “Transmission Protection System” given the regional definition of the BES.
The “zero tolerance” structure proposed within this standard combined with the large volume and complexity of Protection System components requires a utilities processes and built-in grace periods to perform to perfection. Although this is a worthy goal for our industry, this can result in a large number of non-compliances for minor documentation issues or slightly missed maintenance schedules on an insignificant percentage of relays. The processing of these non-compliances can be costly in terms of resources that could be better utilized to address other transmission reliability matters. To provide a better approach, we suggest an incremental carryover system be permitted that would allow up to 0.5 percent of the PRC-005 maintenance task to be carried over to the next period, provided they are random events (not repetitive). As an example, a small percentage of our Protective System Control Trip tests on a 6-year interval could be carried over into the next calendar year when a generator outage is rescheduled. With this provision, these few tests could be handled without risk of a generator trip and without a compliance consequence. These carryover tasks could be addressed through an action plan with a defined completion date, and could be documented through a regional web portal. There are many barriers to 100% completion at a zero tolerance level with this volume of tasks.
Group
Southern Company
Hugh Francis
Yes
 
No
Tables 1a and 1b require entities to verify the proper operation of voltage and current inputs to sensing devices on a 12 year interval. The Protection System Supplementary Reference (Draft 1), in section 15.2, describes several methods that may be used for such verification efforts. In order to perform this type of verification the circuit in question would need to be in operation. This verification introduces a possible unit trip due to the need to connect test equipment to live potential and current circuits at each relay, which has the potential to trip the circuit under test. This could result in the loss of critical transmission lines or generating units. The System Maintenance Supplementary Reference also allows saturation tests or circuit commissioning tests to satisfy this requirement; however, these types of tests require the circuit in question to be removed from service. For generating plants, removing the circuit from service requires that the station be shut down. We do not feel that the value obtained from this requirement is equal to the risk or maintenance burden associated with it. Such testing and verification should not be required periodically, but only if new instrument transformers, cabling or protective devices are installed or if the instrument transformers are replaced. Table 1b: Protection System Control Circuitry (Trip Coils and Auxiliary Relays) – Experience has shown that electrically operating partially monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is not warranted. This testing introduces risk from a human error perspective as well as from additional switching and clearances required. We recommend eliminating this maintenance requirement. Protection System Control Circuitry (Trip Circuits) (UFLS or UVLS Systems Only) - Table 1b includes the statement "Verification does not require actual tripping of circuit breakers or interrupting devices." This statement should be included in Table 1a. In Table 1a – Station DC Supply (that has as a component any type of battery), we recommend changing the maximum maintenance interval from 3 months to 6 months as described below Verify Proper Electrolyte Level – 3 Months The 3 months interval for verifying proper electrolyte level is excessive for current battery designs that are properly maintained. The interval in which the electrolyte must be replenished is affected by many factors. These include temperature, float voltage, grid material, age of the battery, flame arrester design, frequency of equalization, and electrolyte volume in the battery jar. Manufacturers are aware that their customers want to extend the interval in which their batteries require water and this has lead to jar designs that have a wide min-max band with a high volume of electrolyte to allow for extended watering intervals. Understanding all the factors and proper maintenance will extend watering intervals. A battery should go a year or more between watering intervals and some as many as 3 years. Being conservative the Southern Company Substation Maintenance Standards require that we check the electrolyte level twice yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”. • Verify proper voltage of the station battery – 3 Months Being conservative, the Southern Company Substation Maintenance Standards require that we check the station battery voltage twice yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”. • Verify that no dc supply grounds are present – 3 Months Being conservative, the Southern Company Substation Maintenance Standards require that we check for dc supply grounds twice yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”. Measurement of Specific Gravity – 18 Months The measurement of specific gravity and temperature every 18 months is not necessary as a regular part of maintenance. Specific gravity can provide information as to the health of a cell; however, taking specific gravity readings is a messy process no matter how careful you are and will result in acid being dripped on top of the battery jars as the hydrometer is moved from cell to cell. Should a drop of acid end up on an external connection, it will result in corrosion and problems later. Voltage reading of cells can be substituted for specific gravity readings under normal conditions. Specific gravity is equal to the cell voltage minus 0.85. A cell with low voltage will have a low specific gravity. If cell voltage becomes a problem that can not be addressed through equalization then specific gravity readings are justified as a follow-up test. Since measurement of specific gravity could lead to problems and reading cell voltage is a viable alternative, we propose that it be removed from the battery maintenance activities. Verify Cell to Cell and Terminal Connection Resistance – 18 Months Clarification is needed on the expected method for verifying cell to cell and terminal connection resistance. This could easily be interpreted as requiring the use of an ohmic value (impedance/conductive/resistance) test device. If this is the case then basically it eliminates the need for the activity to “Verify that the substation battery can perform as designed by performing a capacity test every 6-Calendar Years or performing an ohmic value test every 18 Months”, because the practical thing to do is go ahead and perform the ohmic value test while you have your device connected to the battery. In table 1a and 1 b - Station dc supply (that has as a component Vented Lead-Acid batteries. Verify that the Substation Battery can Perform as Designed – 6 Calendar Years/18 Months Southern Company Transmission has approximately 570 batteries that are covered by this proposed standard. These batteries currently have ohmic value testing performed every “4 Years” as required by the Southern Company Substation Maintenance Standards. The “4 Years” interval has been utilized for over 10 years and has not experienced a failure of any of the 570 batteries to perform as designed Having to perform ohmic value testing on an “18 Months” interval will significantly increase our costs and manpower requirements with no anticipated improvement in reliability. We propose that the “18 Months” interval for ohmic value testing be changed to “4 Calendar Years”. This proposal also applies to verifying cell to cell and terminal connection resistance if an ohmic value test device is required as discussed above. In table 1a and 1b – Station dc supply (that uses a battery and charger). Verify that the Battery Charger can Perform as Designed – 6 Calendar Years Clarification is needed on an acceptable method for verifying that the battery charger can perform as designed by testing that the charger will provide full rated current and will properly current limit, especially the part about “will properly current limit”. On Table 1b – Station DC Supply (that has a component any type of battery) we recommend changing the maximum maintenance interval from 3 months to 6 months as described below • Verify Proper Electrolyte Level – 3 Months The 3 months interval for verifying proper electrolyte level is excessive for current battery designs that are properly maintained. The interval in which the electrolyte must be replenished is affected by many factors. These include temperature, float voltage, grid material, age of the battery, flame arrester design, frequency of equalization, and electrolyte volume in the battery jar. Manufacturers are aware that their customers want to extend the interval in which their batteries require water and this has lead to jar designs that have a wide min-max band with a high volume of electrolyte to allow for extended watering intervals. Understanding all the factors and proper maintenance will extend watering intervals. A battery should go a year or more between watering intervals and some as many as 3 years. Being conservative the Southern Company Substation Maintenance Standards require that we check the electrolyte level twice yearly. Experience has shown this has worked well. We propose that the “3 Months” interval be changed to “6 months”. We recommend removing the “Detection and alarming of dc grounds” monitoring attribute. Note that this applies to every “Station dc supply” section where it is listed. Experience has shown that there have been no significant problems discovered via alarms that would not have been discovered by 6 month inspection cycles. We propose to add “verify no dc grounds are present” as a maintenance activity on a 6 months inspection cycle. Experience has shown that there have been no significant problems discovered via alarms that would not have been discovered by 6 month inspection cycles. Table 1a, p. 7, Station dc supply, 3 month interval: need to add ‘unintentional” to the sentence “Verify that no dc supply grounds are present.” because most dc systems have ground detection systems which place an intentional ground on the battery. “No grounds” is not practical and is unacceptable since most dc systems have some high resistance ground paths. Some criteria should be established to determine the acceptable ground resistance on a dc system. Table 1a, p. 8: For the vented, lead-acid battery, there is no basis for the 18 month activity option (internal ohmic value measurement) in place of the 6 year performance test. The activities for trip checks for Level 1A and Level 1B should be the same. Currently, they read: Level 1a: “Perform a complete functional trip test that includes all sections of the Protection System trip circuit, including all auxiliary contacts essential to proper functioning of the Protection System. “ Level 1b: “Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is electrically operated within this time interval.” The Level 1a text is adequate for 1b also. Table 1c, p 16: Monitoring of single or parallel trip circuits is not practical where multiple normally open contacts are in series to trip. Monitoring of the trip coils is practical and useful. How would one monitor several normally open contacts which are in series to trip a breaker? Table 1c, p. 15, 16, 19: The use of “continuous” under “Maximum Maintenance Interval” in Table 1c should be changed to “N/A” and the Maintenance Activity should be “NONE”. Verification of the various monitoring (automated notification) systems is not specified anywhere in the requirements. This, too, should be required.
No
The 3 month intervals specified for the trip coil monitoring and communication circuit testing are too frequent. Our experience is that trip coils rarely burn open and don’t need to be checked this often. If no monitoring currently exists, manually checking the circuit (until a time where monitoring can be installed) may inadvertently cause a trip. This adds risk to the reliability. Thus, requiring the trip circuits to be tested every 3 months may reduce the reliability of the BES. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) In order to reduce the risk of reducing Bulk Electric System reliability a better time interval for testing un-monitored trip coils would be 12 months. This may need to be 24 months for Nuclear Generating units. Some allowance for a grace period (beyond the specified intervals) should be considered for all classifications. Outage schedules are known to change unexpectedly due to unforeseen circumstances. A grace period tolerance of +25% for specified maintenance intervals less than 12 months and of +1yr for those intervals specified as greater than 12 months is recommended. Typically at a nuclear plant a grace period is allowed by plant procedures. This grace period is defined as an additional 25 percent of the original schedule interval for the task. The grace period is provided as reasonable flexibility to allow for alignment with surveillance activities and equipment maintenance outages and to better manage the use of station resources. Some maintenance activities will require an outage to perform the work. Refueling outages are typically performed on an 18 month or 24 month refueling cycle. However, refueling outages do not always fall exactly on that interval. It is possible that the duration between one outage to the next may exceed 18 or 24 months. For activities that are required to be complete on a calendar year cycle this should not be an issue since the outages are normally scheduled several months prior to the end of the year. However, if the interval is a monthly interval there could be a problem with scheduling the maintenance such that it does not impact planned maintenance activities, surveillance requirements, and station resources. Tables 1a, 1b and 1c have several instances where inspection and testing of DC circuits or components has a specified interval of 18 months. At nuclear generating stations, such tests on station battery banks and associated chargers incur unacceptable risk if performed with the unit on line and a unit outage is required for this testing. A number of nuclear plants are on two-year shutdown cycles and we request that the 18 month intervals be changed to two (2) (calendar) year intervals to accommodate this. Protection System Control Circuitry (Breaker Trip Coil Only) (Except for UFLS or UVLS) – Based on past performance, a complete functional test trip every 6 years is not warranted. This complete functional test introduces additional risk to our maintenance program, not only from a human error perspective, but also from the additional frequency of switching and outages required. Our experience has shown that 12 years is an appropriate maximum time interval (rather than 6 years.)
No
Table 1b should allow self-monitored circuits that are not alarmed but are monitored and logged by personnel daily or more often. Many plants and substations have personnel that do in person checks of unmanned control rooms. This is the equivalent of “Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for alarmed failures.” For example, dc system ground potential lights and dc system volt meters exist on most control room bench boards or exist in the digital control systems at generating stations. These devices are monitored by operators in manned control rooms. On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays), the monitoring component calls for “Monitoring and alarming of continuity of trip coil(s).” Clarify that “trip coil(s)” excludes Breaker Failure Initiate relay coil(s). On Table 1b, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) – Experience has shown that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is not warranted. This testing introduces risk from a human error perspective as well as from additional switching and clearances required. We recommend eliminating this maintenance requirement from Table 1b. On Table 1c, Protection System Control Circuitry (Trip Coils and Auxiliary Relays) – Experience has shown that electrically operating fully monitored breaker trip coils, auxiliary relays, and lockout relays every 6 years is not warranted. This testing introduces risk from a human error perspective as well as from additional switching and clearances required. We recommend changing this maximum maintenance interval to 12 years. Component monitoring attributes need to be defined for all components in table 1b and 1c. For example, the attributes for voltage and current sensing devices could be that "Voltage and current input circuits are monitored and alarmed". Based on past performance, the requirement to electrically operate trip coils, auxiliary relays, and lockout relays every 6 years in Table 1b is not warranted. We recommend complete functional testing including electrical operation of breaker trip coils, auxiliary trip relays, and lockout relays every 12 years in tables 1b and 1c.
Yes
 
Yes
Section 15.3 DC Control Circuitry: Although we agree with the premise that auxiliary trip relays and lock-out relays are similar in nature to EM relays and breakers, we believe that based on past performance, a complete functional test trip every 6 years is not warranted. This complete functional test introduces additional risk to our maintenance program not only from a human error perspective but also from the additional frequency of switching and outages required. Our experience has shown that 12 years is an appropriate maximum time interval (rather than 6 years.) The Protection System Maintenance Supplementary Reference (Draft 1), section 8.4, states that the intervals using the term “calendar” are allowed to be completed by the end of the applicable period, not necessarily exactly at the interval specified. The only intervals specified in the PRC-005-2 tables are “calendar years” and “months”. We believe that the “calendar” description should be extended to the “months” designator also to also provide some maintenance flexibility (i.e. if an inspection were performed March 1st and was on a three month interval, it would not be required until the end of June). This section should remove the term “calendar” and use “months” and “years” with an appropriate explanation of the intent of the durations.
Yes
Part of the responses could be more correctly stated: Page 11E, “why is specific gravity testing required?” The specific gravity measurements do not reflect accurate state of charge for lead-calcium batteries. (Float current is a better parameter for this indication)
 
 
We presently utilize a UFLS system distributed across many transmission and distribution substations. Are the station batteries located in stations with no network transmission protection schemes (other than UFLS) subject to the requirements of PRC-005-2? This was not addressed in previous revisions. We presently utilize a UVLS system distributed across many transmission and distribution substations. Are the station batteries located in stations with no network transmission protection schemes (other than UVLS) subject to the requirements of PRC-005-2? In the applicability section, there is no exception for smaller units and those with very low capacity factors. Rather, those that “are part of the BES” are in the scope. We recommend that smaller units and low capacity factor units be exempt from the requirements of this standard or have extended maintenance intervals. Refer to the current SERC supplement for PRC-005-1. Section II.A. of the May 29, 2008: SERC Supplement Maintenance & Testing – Protection Systems (Transmission, Generation, UFLS, UVLS, & SPS) NERC Reliability Standards PRC-005-1, PRC-008, PRC-011, & PRC-017. The applicability section paragraph 4.2.4 should read “are installed” rather than “is installed”. Note 2 at the bottom of the table (1c) implies that one has to apply voltage and inject current into the microprocessor relay to perform trip checks. Is this the intent of the statement? If so, Note 2 should be revised to make clear the intention. We don’t think this is necessary with microprocessor relays since they monitor inputs Why is the Violation Severity Level Matrix not a part of this standard revision? In cases where a common dc system exists between a generator owner and transmission owner, who is the responsible entity? We appreciate the work that went into the implementation plan. We agree with the concept of phasing in mandatory compliance and the timing of the implemetation. Consider defining the Monitoring Levels once and reformatting the information contained within Tables 1a, 1b, and 1c to regroup the information by component type rather than by Monitor Level. When considering the various monitoring levels for the protection system components, each entity will consider each component type apart from the others when determining the Monitor Level to apply, so this reorganization will assist the end user to understand and apply the levels. See samples attached as a separate document:
Individual
Daniel J. Hansen
RRI Energy
Yes
 
No
It is recommended to change the wording of the Maintenance Activities to the activity itself, not the resolved state of the maintenance correctable issue (i.e. “For microprocessor relay, check for proper operation of the A/D converters” instead of “For microprocessor relays, verify proper functioning of the A/D converters”). The wording of the standard effectively sets the end date for the correction of maintenance identified issues. In other words, maintenance has not taken place until all maintenance correctible issues have been completely resolved. The wording in the standard have set non-compliance “traps” for those performing the maintenance but have not completed correctable issues for legitimate reasons which may not be allowed by the no-exception approach of the standard. For example, rewording of the Battery Supply 3 month activities are recommended as follows: “Check for proper electrolyte level. Check for proper voltage. Check for dc supply grounds.” As inspection activities, any issue not corrected during the interval should become a maintenance correctible issue. For generating stations, the judgments to locate and remove a ground are based upon criteria not accounted for in the requirements of this standard. An activity to locate and clear a ground requires the judgment of station maintenance and operational management depending upon the operating conditions of the unit and the level of the ground (solid or high-resistance). Inspections (3 month requirement activities) although good practices, should not be standard requirements. The practice of verifying the continuity of breaker trip circuits does not belong as an auditable NERC standard requirement; it becomes more of a documentation requirement rather than a reliability improvement. Otherwise, it will ultimately require the expending of resources in an unproductive manner primarily on the development, storage, and production of excessive records for compliance purposes. The elimination of this requirement is recommended. For Table 1a – Protection System Control Circuitry - rewording is suggested as follows: “Perform functional trip tests of Protection System trip circuits, including auxiliary relays essential to the proper functioning of the Protection System.” The requirement, as presently worded “that includes all sections of the Protection System,” is overly prescriptive and will create non-compliances for miniscule oversights, given the very large scope of components in protection systems that are spread out far and wide in a system. The requirement opens the door, allowing the compliance process itself to be punitive in nature. When pursued to the extreme under audit conditions, this requirement will be very difficult to demonstrate on a large scale. For Table 1a – Station dc supply: The ability of a battery charger to correctly supply equalize voltage to a battery has no direct correlation to reliability of the BES and does not belong in this standard. The objective is that the battery get an equalize charge when it needs it, not the maintenance of the equalize function of a battery charger. How the battery gets equalized is not important to this standard, especially since a battery and the equalize source are usually disconnected from the protection system during the process. For Table 1a – Station dc supply: The use of the term “in tolerance,” for the measurement of specific gravity, is an inconsistency in stating the standard requirements. There are multiple activities that will necessitate the measurement of a quantity “in tolerance” whether it is battery charger output, individual cell voltages, connection resistances, or internal ohmic values. The suggested rewording is as follows: “Measure the specific gravity and temperature of each cell.” For Table 1a – Station dc supply: Referring to the requirement to “verify that the station battery can perform as designed…” very little of a generating station battery sizing is related to BES protection. Verification of a generating station to design conditions is outside the scope of BES protection and does not belong in this standard. Nearly all protection system operations operate without reliance upon the battery to do so, and the separation of the generating unit from the BES will take place within cycles, if called upon to do so. The remainder of the battery duty cycle is outside the scope of BES protection.
No
The intervals need to be defined on a calendar quarters or calendar years, especially for intervals listed as 3 months. The demonstration of maintenance on rolling three-month intervals will be an onerous record keeping task, particularly when relying upon planning and tracking software that scheduled recurring tasks on the same day of an interval. Given the magnitude of the number of trip circuits, the requirements set an un-acceptable trap of non-compliance from a record keeping perspective. The resources required to keep and maintain flawless records are too much to justify the intervals. A non-compliance is the result if the breakers that happen to be in an open state when the officially “documented” inspection is recorded and is missed by accidental oversight on follow-up. If the requirement remains, it should be waived for any breaker that is operated during the defined interval.
Yes
 
Yes
 
No
 
Yes
Reverse power relays do not belong in the list of devices within the scope of this standard; reverse power is not used for generator protection or protection of a BES element. Aside from the protection of reverse power for other non-BES equipment, a generator can operate continuously as a generator, synchronous condenser, or a synchronous motor. Reverse power relays (or reverse power elements in multi-function relays) is commonly used as a control function for automatic shut-down purposes, which is not a protective function. Other reverse power protection, with longer time delays, is provided for turbine protection, which is not within the scope of the NERC Standards.
 
 
The standard was written to implement generally accepted practices, but has developed requirements that are overly prescriptive relative to what will be required to demonstration compliance. The standard should not assume the need to write all aspects of a maintenance program into the standard or that maintenance programs will only consist of the standard requirements. Protection systems of the BES have and will continue to perform very reliably with the basic elements of a maintenance program without the need to divert resources for the development of excessive documentation to demonstrate compliance. PRC-005-1 is the most violated standard in the industry; not because of the lack of maintenance to protection systems, but because the documentation requirements of the standard, given the large magnitude of components that fall within the scope of the standard. This standard significantly increases the administrative burden for additional documentation, without corresponding improvements to the reliability of the BES. Recommend rewording A.4.2.5.1 as follows: “Generator Protection system components that trip the generator circuit breakers to separate and isolate the generator from the BES either directly in the breaker trip coil circuit or through interposing lockout or auxiliary tripping relays.” This document should not expand the compliance scope beyond the definition of the BES. The generator protection systems that “trip the generator” also perform additional control functions that extend beyond the electrical isolation of the generating unit from the BES. These additional circuits do not protect the BES and do not belong in the scope of this document. Recommend rewording A.4.2.5.4 as follows: “Protection systems for generator-connected station service transformers that trip the generator circuit breakers to separate and isolate the generator from the BES.” This document should not expand the compliance scope beyond the definition of the BES. Related protection circuits of the transformer not involved with the electrical isolation of the generating unit from the BES does not belong in the scope of this document. Recommend rewording A.4.2.5.5 as follows: “Protection systems for BES elements connecting to the station service transformers of generating stations.” This document should not expand the compliance scope beyond the definition of the BES. The requirement incorporates radial feeds (with dedicated breakers) into the scope of the standard that are not necessarily a part of the BES as defined by some RRO’s. Station service transformers are not necessarily required for generating unit operation. In some cases there are redundant sources for startup or back-up power. Protection of these transformers does not belong in the scope of the standard if they are not a part of the BES. The suggested rewording of R1.2 is as follows: “Identify whether each Protection System component is addressed through time-based, condition-based, performance-based, or a combination of these maintenance methods.” The requirement for the registered entity to list the interval of maintenance does not belong in the standard, especially since the maximum intervals are listed in the standard tables. The registered entity may have internal documents that intentionally target a shorter duration than the maximum interval of Table 1a. The failure to meeting those internally established targets can be a violation of the standard by the wording of this requirement. Allow R4 of the standard to identify the maximum allowable intervals. In R4, the requirement for “identification of the resolution of all maintenance correctible issues” should be separated from the maintenance intervals; which define the maximum intervals of maintenance activities. The requirement should be eliminated to remove the overly prescriptive requirements of auditable documentation. If retained, a rewording of the requirement is as follows: “Each Transmission Owner, Generator Owner, and Distribution Provider shall identify the resolution of all issues identified and not corrected at the time the maintenance is initiated and the protected element is returned to service.” The documented resolution of maintenance correctible issues (if retained) should apply only to activities that are unresolved and incomplete during the normal maintenance process. The standard should not micromanage the documentation process by creating requirements for excessive auditable records needed to demonstrate compliance of routine maintenance activities. In R4, the requirements for Generator Owners which establish the durations of maximum allowable intervals should be separated from the Transmission Owners, even if the intervals are the same. The reason is to allow for the assignment of different Violation Risk Factors. The Violation Risk Factor for the application of a 20 MVA generating unit with an operating capacity factor of less than 5%, and connected to a 138 kV system, should not be the same as those applied to a 500kV transmission line. The violation risks factors for these two applications are significantly different, and the ability to recognize this is not permitted by the standard presently. Similarly, the criteria used for the sizing of station batteries for a large generating station is very different than those used for transmission facilities. Very little of the generating station battery sizing is related to BES protection, and nearly all generator protection system operations occur without reliance upon the battery. Without NERC Standard requirements, Generator Owners have their own natural incentives to maintain batteries for the protection of the turbine generator bearings on the loss of AC power. With the most basic requirements of an inspection and maintenance program, there is an extremely high degree of reliability given the typical design of DC systems within a generating station, even without documented compliance to a rigid set of standards. With very basic, elementary maintenance (documented or not), the statistical probability for the random and simultaneous failure of multiple battery cells to disable the protection system of a generating station for the milliseconds of time required to separate a generating unit from the BES is insignificant (well in excess of 1 billion to 1 across an entire calendar quarter). Violation risk factors and the resulting penalties for non-compliance need to be realistic.
Group
Transmission Owner
Silvia Parada-Mitchell
Yes
 
No
Tables 1a, 1b & 1c should offer as an alternative, measuring battery float voltages and float currents in lieu of measuring specific gravities as described in Annex A4 of IEEE Std 450-2002. b. Inspection of CVT gaps, MOVs and gas tubes should be added to the communications equipment time based maintenance tables. Failure of the CVT protective devices may cause failure of the Protection System. c. Maintenance Activities for UVLS or UFLS station dc supplies shows “Verify proper voltage of dc supply”. Does this imply that, except for voltage readings of the dc supply, distribution battery banks are not maintained? d. Why does the Maintenance Activities for UVLS or UFLS relays state that verification does not require actual tripping of circuit breakers? e. Please clarify the Maintenance Activities for Voltage and Current Sensing Devices. Must voltage, current and their respective phase angles be measured at each discrete electromechanical relay?
No
i) Protective relays, ii) Protection Control Circuitry (Trip Circuits) and iii) Protection System Communications Equipment and Channels should be changed from 6 calendar years to 8 calendar years. Based on FPL’s experience and Reliability Centered Maintenance (RCM) program, FPL has established an 8 year program and has found that an aggressive 6 year program would not substantially increase the effectiveness of a preventative maintenance program. b. Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past. c. The maximum maintenance interval for communications equipment should be changed from 3 months to 12 months. Based on FPL’s experience and RCM program, FPL has established a 12 month program that is effective.
Yes
 
Yes
 
No
 
Yes
An alternative to measuring battery specific gravity is to measure float voltage and float current as described in Annex A4 of IEEE Std 450-2002.
 
 
Protection System Maintenance Program (PSMP) The PSMP definition would be better defined if the first sentence was changed to “An ongoing program by which Protection System components are kept in working order and where malfunctioning components are restored to working order.” b. Please clarify what is meant by “relevant” under the definition of Upkeep. Should “relevant” be changed to “necessary”? c. The definition of Restoration would also be more explicit if changed to “The actions to return malfunctioning components back to working order by calibration, repair or replacement. d. Please clarify the definition of Restoration. For example, if a direct transfer trip system has dual channels for extra security even though only one channel is required to protect the reliability of the BES and one channel fails, must both be restored to be compliant? e. Protection System (modification) ”Voltage and current sensing inputs to protective relays” should be changed to “voltage and current sensors for protective relays.” Voltage and current sensors are components that produce voltage and current inputs to protective relays. f. “Auxiliary relays” should be changed to “auxiliary tripping relays” throughout PRC-005-2, FAQ and the Draft Supplementary Reference. g. The word “proper” should be removed from the standard. It is ambiguous and should be replaced with a word or words that are clear and concise.
Individual
Greg Mason
Dynegy
Yes
 
No
Table 1a requires entities to "verify the continuity of of the breaker trip circuit including trip coil..." The term "verify" needs clarification. For example, we beieve verifying red and green" lights during routine inspection should be sufficient. On the other hand, actual testing is not feasible and is risky to reliability.
No
The 3 month interval in Table 1a for verification of the continuity of the breaker trip circuit is only feasible if this verification can be done by inspection versus testing (see Response to Question 2).
Yes
 
Yes
 
Yes
Suggest including operational verification (i.e. analysis of protection system operation after a system event) as an acceptable method of verification.
No
 
 
 
1. The proposed definition of Protection System needs further clarification. Suggest changing wording around DC supply to read as follows: "..and DC control circuitry associated with protective devices from the station DC supply". 2. Suggest revising Section 4.2 to separate time based program as its own item under R4. 3. Change title on Table 1a to clarify level 1 monitoring as time based.
Group
ITC Holdings
Michael Ayotte
Yes
 
No
• (FAQ 3C) What is the technical justification for omitting insulation testing of the wiring for DC control, potential and current circuits between the station-yard equipment and the relay schemes? We feel this wiring is susceptible to transients which, over time, may compromise the insulation, and therefore should be tested. • Table 1a (Page 6) Improve wording. Suggestion: “Verify proper functioning of the current and voltage circuits from the voltage and current sensing devices to the protective relay inputs” • On Page 6: The red light monitors trip circuit not only trip coil. With only one circuit going to three parallel single-pole trip coils a red light will not detect a single open trip coil. Is a station inspection that verifies the red light is “on” an acceptable activity? • On Page 9: The 3 month communications maintenance activities should say that the channel needs to be checked. For example: initiate a manual checkback test of the carrier system. • On Page 10: Not clear on level 2 monitoring attributes for protective relay component description. As written it notes two separate requirements which are ambiguous. We assume that all monitoring noted is required (internal self diagnosis and waveform sampling) • On Page7: The standard should note that battery testing must include all batteries that are used in protective relay systems (for example pilot wire batteries).
No
• Does the standard require that time or condition based maintenance programs monitor countable events to identify significant problems in particular relay segments, and then adjust the maintenance interval accordingly? • On page 6: Please clarify the use of “Calendar Year” Our understanding is that if a relay is maintained on August 31, 2003 on a 6 year interval, it will not be overdue until January 1, 2010. Is this correct? • On Page 7: What is the basis for 18 months? We believe 2 calendar years would be more appropriate. • On Pages 6,10: What is the basis of the 6 calendar year interval for functional trip tests? We request that this be changed to a 10 calendar year interval. We follow a 10 calendar year interval that has proven to be satisfactory. Decreasing the interval to 6 calendar years will result in a major increase in our maintenance expenses without a corresponding increase in reliability. • On Page 9: If it is being verified ok every 3 months, what is the basis of the 6 calendar year interval for Communication equipment? ITC communications systems are partially monitored and therefore required to perform this testing every 12 years. However, ITC would like to know the basis of the 6 year interval for informational purposes. • On pages 6, 8, 11, 13, 14 and 19: The maximum maintenance interval “(when the associated UVLS or UFLS system is maintained)” should be shown as the actual “6 Calendar Years”. • On Page 1 of Attachment A: Please provide an example in the reference of the proper way of adjusting the interval based on test results. • On Pages 7, 8, 12: It is our understanding that adequate maintenance can be achieved by performing either one of the two maintenance activities in cases where there is an “or”, is that correct? • On Page 14: For the bottom two rows on page 14 we believe there is a typo and it should read “Level 2” not “Level 1”. • On Page 13: Do powerline carrier schemes that provide a remote alarm if a daily checkback test fails, meet level 2 monitoring requirements? • In Table 1: What is the basis for the 6 year interval for the battery systems? This test would be an additional test for ITC. We would prefer to perform this additional test with the relay periodic maintenance on a 10 year interval.
Yes
• We agree with the approach. We have several issues with the details of Maintenance Issues, Interval and Monitoring Attributes. See previous comments for Questions 2 and 3.
No
• Appendix A fixes a 4% level of “countable events”. Is this number the industry average for countable events? Has the industry average actually been determined? The basis for the 4% requirement noted in Paragraph 5 of Appendix A should be included in the reference document. Also a sample calculation for adjusting the interval is needed to clarify the requirement.
Yes
• Will clarifications in the Reference Document be enforceable with the standard? For example page 11 of the reference document notes “Voltage & Current Sensing Device circuit input connections to the protection system relays can be verified by comparison of known values of other sources on live circuits or by using test currents and voltages on equipment out of service for maintenance.” Can a maintenance program be confidently established using this or other testing methods included in the reference document? • A condensed definition of “Condition Based Maintenance” as described in Section 6 of the Reference document should be included in the standard document itself.
Yes
• FAQ page 6 question 3C should be clarified in the standard document itself. What is the technical justification for omitting insulation testing of the wiring for DC control, potential and current circuits between the station-yard equipment and the relay schemes? We feel this wiring is susceptible to transients which, over time, may compromise the insulation, and therefore should be tested. • FAQ page 17 question 2A the standard should define when the first maintenance activity is to be performed. We include our maintenance activities during commissioning, and set the next maintenance due date based on the testing interval. • Will clarifications in the FAQs be enforceable with the standard? Can a maintenance program be confidently established using this or other answers included in the FAQ’s?
Comments: We are not aware of any conflicts.
Comment: We are not aware of any regional variance or business practice that should be considered with this project.
In the Definitions of Terms, the Protection System (modification) should include control circuits up to and including the trip coil of ground switches used in protection schemes. Footnote 2 (Maintenance correctable issue) should be included in the Definition of Terms in the body of the standard.
Individual
Robert Waugh
Ohio Valley Electric Corp.
Yes
 
No
In general, all maintenance activities that are verifications of proper function imply that problems found must be resolved within the maximum interval. For some activities, that is an unreasonable expectation. A temporary resolution may reliably correct an adverse situation but may not address the original verification requirement within the maximum interval. Routine substation inspections should not fall under NERC standards. The documentation for quarterly inspections would be oppresive. It is unreasonable to require there to be no DC grounds. All DC grounds do not rise to the level of a reliability concern. In some cases, attempting to resolve a relatively minor DC problem may rise to the level of negatively affecting reliability. The value of capacity testing battery banks and chargers in the context of a protection system reliability standard is questionable.
No
The documentation requirements for the inspection activities with three month intervals is oppressive and should not be a part of the protection system maintenance standard.
 
 
 
 
 
 
R1.2 seems to require owners to establish there own intervals and basis. Compliance with these requirements should be based on the intervals that are in tables 1a, 1b and 1c. R4 implies that all maintenance correctible issues must be resolved within the Maintenance Activity Intervals. A diligent effort to restore proper function of a system should not be penalized if it does not fall within the prescribed maintenance interval.
Individual
Brent Ingebrigtson
E.ON U.S.
 
No
Capacity or AC impedance only needs to be done to determine service life and therefore periodic testing of station DC supply does not seem necessary or prudent. If a company checks overall battery bank voltages quarterly then periodic testing of the battery bank charger should not be required.
No
Generally, E.ON U.S. requests that the SDT provide the basis for the proposed changes in maintenance time lines. E ON U.S.’s existing maintenance intervals are based on actual operating experience. Not having been provided with the basis for the proposed intervals, the time lines appear arbitrary. E.ON U.S. currently has an 8-year interval for combustion turbines vs. the 6-year interval provided here. The E.ON U.S. interval is based on the Company’s experience with this equipment. E.ON U.S. suggests that the SDT provide some consideration to individual entities’ historic practices. It is difficult to track “18 months”. Maintenance intervals should be in expressed in number of years. E ON U.S. also does not understand the basis for the 3 months maintenance schedule on breaker trip coils. Typically, the circuit breaker closed indication is wired through the breaker trip coil. Thus there could not be a breaker closed indication without a good breaker trip coil. So, this test should be considered continuous monitoring which may not even require documentation except in case of failure.
Yes
 
No
E.ON U.S. recommends keeping with time-based intervals (and the improvement thereof) and staying clear of condition-based performance for the generating stations. But that is not meant to preclude other companies from doing condition-based, if they so prefer.
Yes
With reference to Section 8.1., under additional notes is the following bullet: 5. Aggregated small entities will naturally distribute the testing of the population of UFLS/UVLS systems and large entities will usually maintain a portion of these systems in any given year. Additionally, if relatively small quantities of such systems do not perform properly, it will not affect the integrity of the overall program. This implies that incorrect performance of a “relatively small quantity” of UFLS relays is acceptable but with the understanding that it is not optimal. E.ON U.S. agrees with this statement in principle, in that the UFLS program is spread out across the system, and there is not a one to one performance expectation as there is with a transmission line or generation protection system. This calls into question the required intervals for testing of these types of relays, and the performance expectations in a PBM program. Given the number of relays spread out across the distribution system, the testing requirements of UFLS relays require longer testing intervals than other bulk transmission system components. 8.2 Is this requirement expected to be retroactive? That is, if the previous retention policy was followed to the letter, an entity could be fully in compliance based on the previous standard, but not be in compliance if PRC-005-2 were retroactive. 8.3 And 8.4 This discussion explains how time based maintenance intervals were determined. The conclusion is based upon surveys of SPCTF members and their existing practices, and seemed to arrive at a maintenance interval based upon a simple average weighed by the size of the reporting utility. No consideration appears to have been given to utilities who have successfully operated with longer test and calibration intervals. In section 5 of the Supplementary Reference it is stated that “excessive maintenance can actually decrease the reliability of the component or system.” With that in mind, some of the intervals defined in the table seem too aggressive. With the proposed PRC-005-2, the Drafting Team has effectively shortened the recommendation for UFLS relays from 10 years to 6 years, with reference to the recommendations of the Protection System Maintenance Technical Reference. E.ON U.S. believes that this is inconsistent with previous comments in Section 8.1, bullet 5 of the notes. Consistent with the comments above and based on E ON U.S.’s internal testing, calibration and verification experience, E.ON U.S. recommends maintenance on UFLS relays that comprise a protection scheme distributed over the power system to be no less than 10 years for Level 1 monitoring and no less than 15 years for Level 2 monitoring. For a PBM program, require the number of countable events within a segment to be no more than 10%, not 4% as proposed.
No
E.ON U.S. disagrees with commissioning tests not being considered as a baseline for subsequent maintenance activities. Commissioning tests should be counted as the initial testing in the scheme of a maintenance program
 
 
Recently, NERC made an interpretation on PRC-005-1 which stated that battery chargers were not to be included as part of the standard. This version of the standard seems to be in direct conflict with that interpretation, and for the reasons stated above E.ON U.S. recommends that battery chargers not be included in the standard. E.ON U.S. believes that capacity or AC impedance only needs to be done to determine service life, and therefore a periodic testing of station DC supply does not seem necessary or prudent. Regarding the “Retention of Records”, retaining records of the latest test seems adequate. E.ON U.S. does not understand the point of retaining records for the past two test results. This is particularly true for equipment for which there are relatively long testing intervals, for example, 12 years. Retaining result documents from 24 years ago seems unnecessary and impractical. With regard to NERC’s PRC-005-2 Supplementary Reference Section 2.4 on Applicable Relays, E.ON U.S. offers the following comments: 1. This section extends the applicable relay coverage to IEEE type # 86 and IEEE type # 94. Some utilities define their turbine trip relay as an IEEE type #94. E.ON U.S. interprets that the NERC scope of applicable relays is that the turbine trip relays would be excluded; however, it would further clarify this exclusion if it were mentioned as an example in the last sentence. 2. The Tables in proposed Standard PRC-005-2 require additional clarity. E.ON U.S. suggests renaming tables to 1, 2 and 3 to match Level 1, 2 and 3 monitoring. The wording and format of text is not consistent between tables. 3. The fields in the tables are incoherent. E.ON U.S.’ interpretation is that intervals and activities for UFLS and UVLS are different than other relay systems and components, but this is unclear. E.ON U.S. believes a separate table or sections for UFLS and UVLS would provide more clarity. In section 7 of the Supplementary Reference the SDT refers to the Bulk Power System instead of the Bulk Electric System. These are not interchangeable and the SDT needs to explain the need to use the term in this case. The phrase “support from protection equipment manufacturers” is used several times in the technical reference (Section 8 and Section 13) yet there is no manufacturer represented on the SDT. Rather than developing one size fits all requirements applicable to all equipment, E.ON U.S. suggests that the SDT pursue comments from manufacturers to obtain recommendations on what they believe is required to maintain and test their equipment.
Individual
Danny Ee
Austin Energy
Yes
 
No
See item # 10 Comments
No
See item # 10 Comments
Yes
 
No
See item # 10 Comments
Yes
 
Yes
 
 
 
Austin Energy is meticulous in adhering to the current maintenance standard and is convinced that its current maintenance and documentation program is adequate to maintain its reliable electric power system. Austin Energy appreciates the good intentions of the SDT but believes that the approach taken increases complexities to the maintenance process, introduces unwarranted workload in excessive documentation, is inflexible towards system configuration and experience, and is over prescriptive in nature. The approach also fails to distinguish the harmful effects of over-maintenance, increasing reliability risk due to human error and ultimately affecting the overall performance and reliability of the system. Another concerning issue is the addition of the breaker trip coil to the protection system definition. Our position is that the trip coil should be part of the breaker. The protection system would be considered operating correctly if it provided the output signal for the trip coil when expected. Hence the trip coil should be excluded from the new protection system definition. Performance based maintenance as specified in the attachment is extremely difficult and cumbersome to navigate. The intricate requirements are difficult to comprehend and will entrap entities making a good faith effort to comply. We believe this approach may become burdened with undesirable consequences. Last but not least, Austin Energy believes that under-frequency load shedding (UFLS) and under-voltage load shedding (UVLS) systems should not be included in the scope of this new proposal. UFLS and UVLS are a wholly different entity as compared to the Bulk Electric System (BES). Rigidity imposed onto distribution system equipment, operating schemes and performance is uncalled for and overreaching.
Individual
John Alberts
Wolverine Power Supply Cooperative, Inc.
No
Wolverine Power has concern about the level of "prescription" in this standard draft. The intent of the standards is to define what, not how. This draft gets unnecessarily preseciptive in our opinion, particularly in the table
No
The tables are too prescriptive - The standards should state what, not how.
No
See question 2 response
No
See question 2 response
No
See question 2 response
No
 
No
 
 
 
 
Individual
Willy Haffecke
City Utilities of Springfield, MO
Yes
 
No
CU has concern over the battery charger testing requirements. Per the charger manufacturers recommendations there is no reason to test the chargers as proposed in PRC-005-2. It is their opinion that the chargers are self diagnostic and do not require these tests (full load current and current limiting tests). The charger O&M manuals do not even provide instructions for such tests as optional. Therefore, CU takes exception to this requirement and suggests that battery chargers be maintained and tested in accordance with manufacturer’s recommendations. Additionally, CU is concerned with the wording in Table 1a concerning Protection system communication equipment and channels. We are unsure what the maintenance activity actually means. If this is an unmonitored system, how can you verify the condition of the communication system? Is the Standard referring to local monitoring such as annunciators? Please provide clarification.
No
CU agrees in general with many of the maximum maintenance intervals. However, we disagree with the necessity to verify the continuity of trip coils every 3 months. We would be interested to know what basis the committee used to arrive at all intervals. Furthermore, it is our opinion that even if a component is unmonitored, the interval should not surpass the manufacturer’s recommendations.
Yes
CU agrees with the approach, but, may not agree with the exact wording in the tables. For instance, the use of the word “every” in table 1c in “Protection System components in which every function required for correct operation of that component is continuously monitored and verified” may be overstating the level of monitoring that would realistically enable a Protection System to use table 1c.
No
It appears that Attachment A was written for large utilities. Some allocation needs to be made for utilities with smaller numbers of components.
No
 
No
 
CU is unaware of any conflicts.
CU is not aware of a need for a regional variance.
As proposed, this Standard is very long and complex. Additionally,in requirement R1, bullet 1.1 ought to state “For each component used in each Protection System, include all “applicable” maintenance activities specified in Tables 1a, 1b and 1c”. For instance, if every component has continuous monitoring, why should the program include 1a and 1b?
Group
Pepco Holdings Inc. - Affiliates
Richard Kafka
Yes
 
No
Tables 1a, 1b and 1c all require measuring specific gravity and temperature of battery cells. This invasive test provides no information regarding battery health that cannot be obtained from cell impedance testing. Recommend requiring cell impedance OR specific gravity & cell temperature testing. Tables 1a, 1b and 1c all require testing the battery charger every 6 years to verify that it can provide full rated current and will properly current limit. In order to perform this (unnecessary) test the battery would be subjected to a deep discharge. Whatever benefits may be derived from this test are dwarfed by the negative effect on the battery. Recommend removing this requirement.
No
Table 1a requires verification of the continuity of the breaker trip circuit every three months in the absence of a trip coil monitor. Recommend maintenance interval to match that for other protection system control circuitry (6 years).
No
Monitoring and alarming of the station dc supply and detection and alarming of dc grounds are required to qualify for Level 2 monitoring of battery / dc systems. While the presence of dc ground may affect protection and control operations, they do not affect any of the systems for which dc ground alarming is listed as a monitoring criteria. Recommend removing this criterion from the battery & dc system monitoring criteria and adding it as a maintenance activity, with frequency of testing based on presence of detection / alarming.
Yes
 
No
 
No
Item 3.B. (Page 6) claims that a small measurable quantity in 3I0 and 3V0 inputs to relays -may- be evidence that the circuit is performing properly. This statement is weak at best, and incorrect at worst. A balanced transmission system may exhibit 3I0 and 3V0 quantities that are not measurable, and those that are measurable cannot be compared to other readings, since CT/PT error often exceeds system imbalance. Since these inputs are verified at commissioning, recommend that maintenance verification require ensuring that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close to 0.
 
 
 
Individual
Charles J. Jensen
JEA
Yes
Generally agree; however, some suggestions for possible changes: 1) change "associated communication systems necessary for correct operation of protective devices" to "protective relays", 2) add a PSMP glossary defintion for an acceptable type of monitored alarm, either to the proposed "PSMP monitor" or another definition for "PSMP monitored and alarmed." The SDT did a good job of making the overall Protection System definition clearer.
Yes
If a communication system relies on a battery system independent of the "station battery", is this communication system battery under the same requirements as the "station battery"?
 
Yes
Is it possible that for coil monitored equipment, such as LOR coils, that they were left out, of this Table allowing for a longer maintenance interval. Certainly LOR continuous coil monitoring with alarming to a 24 hour 7 day a week manned location, with emergency dispatch, would allow for a longer maintenance interval for continuously monitored LORs. Suggestion here might be alignment with continuously self-tested, monitored and alarmed microprocessor relays at 12 years.
Yes
Approach appears to be well explained. Only one are of concern and that would be delaying the advancement of replacement of EM relay systems with microprocessor, if the PBM population were to decrease below the 60, resulting in not meeting the sample minimum population criteria. Falling below this 60 population sample minimum, might result in an immediate compliance violation.
No
 
Yes
The FAQ is a well written document and the team should take pride in its clarity and informative content. One area that would be good to have further clarification, is if the SDT could provide a current industry product or example of the "software latches or control algorithms, including trip logic processing implemented as programming components, such as a microprocessor relay that takes the place of (conventional) discrete componenet auxilary relays or lockout relays that do not have to be routinely tested." Is this a microprocessor lockout relay (that does not require trip testing?)
 
Regional Variance
Regional variances in the Bulk Electric System defintion as applied across regions allows for PSMP to vary possibly even for the same region crossing tie lines. Also, accepted maintenance practices by one region vary from accepted maintenance practices from another region. In the case of lower kV non-redundant bus lockout protection systems, one region may allow for the prtoection system to be taken out of service to perform maintenance, while another region may specifically prohibit this practice (don't leave energized equipment protected by delayed clearing, etc.)
Implementation Plan - Stongly encourage keeping the implementation plan and allow for an extension of the implementation plan for the time required to fund, design, procure, install and commission redundant protection systems for current non-redundant lockout systems at the lower kV levels of the BES. Our present and past performance of LOR and auxilary relays will support a PBM/CBM program that allows for a much longer time than the six years proposed for EM LOR trip testing. To use a TBM for LORs of six years, may in fact, lower the reliability of the BES due to the complete outages required, along with the detailed procedures that must be created and rigourously followed to perform these tests without subsequent load loss on the BES.
Group
Detroit Edison
David A Szulczewski
Yes
 
No
Suggest that under “Maintenance Activities” for “Protective Relays” add the following: Verify proper functioning of the microprocessor relay external logic inputs (carrier block, etc.) We recommend not requiring specific gravity and temperature readings for batteries. We have found from experience that the time and difficulty to obtain specific gravity readings are not justified. We have found that utilizing visual inspections, voltage and internal/intercell resistance readings gives a good picture of the health of the battery. We use specific gravity readings on occasion for troubleshooting purposes. It is recommended that the sections about verifying battery charger performance be eliminated if there are low voltage alarms that go to a monitored location. We recommend changing the maximum maintenance interval for DC supplies with no battery from 18 months to 3 years. If there is no battery, you do not have the risk of failure of chemical processes and such that would require an interval as short as 18 months.
No
What is the basis for the three month interval for verifying breaker trip coil continuity? Will the investment required to facilitate this really result in the presumed expected increased reliability?
No
Table 1b indicates that this (level 2) includes all elements of level 1 monitoring. However, level 1 is constantly referred to as unmonitored in other places.
Yes
 
No
 
Yes
Example #1 on page 21 states “A vented lead-acid battery with low voltage alarm connected to SCADA. (level 2)”. However, Table 1b indicates that detection and alarming of dc grounds is also required for level 2.
 
 
Suggest that the term “alarmed failures” in the table headings be changed to “alarmed abnormalities” to better indicate that the monitored parameter may be in an abnormal state or out of range but not necessarily failed. Does “system-connected” station service transformers refer to transformers connected to the BES or transformers connected to a system at any voltage level? Is the intent of R1.1.2 that each Protection System component (specific relay at specific location) be listed individually with its associated maintenance method and interval or can the general component category be listed as such? Regarding R4, further clarification would be helpful in understanding the intent of the term “resolution of all maintenance correctible issues” as it applies to R4.1 and R4.2. Is it intended that “maintenance correctible issues” be completed within the interval? It is recommended that each line in the tables be given a number or letter designation to make reference to that row easier.
Individual
Greg Rowland
Duke Energy
Yes
 
No
Our comments are limited to activities in Table 1a. • Protective Relays – okay • Voltage and Current Sensing Devices Inputs to Protective Relays – Proper functioning should be verified at commissioning, and then anytime thereafter if changes are made in a PT or CT circuit. Additional periodic checks may be warranted as suggested in Table 1A, however no additional checking should be required where circuit configuration will inherently detect problems with a PT or CT. For example, PTs & CTs that are monitored through EMS or microprocessor relays will be alarmed when they are out of specification. • Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) – Need more clarity on exactly what this activity is expected to include. In some cases we have a red light on a control panel monitoring the circuit path to the trip coil. In locations where there is not a red light, verifying the continuity of the breaker trip circuit including the trip coil will be complicated. There is no straightforward way to do it without potentially impacting reliability, and we would have to consider modifying these installations to include a red light. • Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) – Need more clarity on exactly what the activity is. We believe testing one output all the way to the coil is sufficient to prove the trip path. The activity states that “all auxiliary contacts” must be tested. We propose that all protection control circuitry should be tested at initial commissioning, and then again if any changes are made. Ongoing routine testing is complicated and could pose reliability challenges to the BES. As stated on page 8 of the System Maintenance Supplementary Reference document: “Excessive maintenance can actually decrease the reliability of the component or system. It is not unusual to cause failure of a component by removing it from service and restoring it. The improper application of test signals may cause failure of a component. For example, in electromechanical overcurrent relays, test currents have been known to destroy convolution springs. In addition, maintenance usually takes the component out of service, during which time it is not able to perform its function. Cutout switch failures, or failure to restore switch position, commonly lead to protection failures.” • Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) – Need additional clarity on exactly what the test includes. “Complete functional trip test” should not include tripping the breaker. Proving the output of the relay should be sufficient. Systems that have all load shed on distribution circuits should require that trip output be confirmed but should not be required through to the trip coil due to constraints in tying distribution load. • Station dc supply (that has as a component any type of battery) – Under the 3 month interval activities, we disagree with the wording of the activity “Verify that no dc supply grounds are present.” The activity should instead read “Check for dc supply grounds and if any are found, initiate action to repair.” • Station dc supply (that has as a component any type of battery) – Under the 18 month interval activities, what is meant by “Verify continuity and cell integrity of the entire battery”? Also what is required to “Inspect the structural integrity of the battery rack”? The “Supplementary Reference Document” and “Frequently asked Questions” document should be made part of the standard to provide clarity to the requirements. • Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) – Need more clarity on exactly what is required for a “performance or service capacity test of the entire battery bank”. The “Supplementary Reference Document” and “Frequently asked Questions” document should be made part of the standard to provide clarity to the requirement. • Station dc supply (that has as a component Vented Lead-Acid batteries) – Need more clarity on exactly what is required for a “performance, service, or modified performance capacity test of the entire battery bank”. The “Supplementary Reference Document” and “Frequently asked Questions” document should be made part of the standard to provide clarity to the requirement. • Protection system communication equipment and channels – Need additional clarity on exactly what is required for the substation inspection. What is required for power-line carrier systems? • UVLS and UFLS relays that comprise a protection scheme distributed over the power system – Need more clarity regarding the meaning of “distributed over the power system”.
No
Our comments are limited to Table 1a. More clarity is needed for many of the Maintenance Activities before assessing whether or not the intervals are reasonable. But as a general comment we would like to understand the basis used to develop all of the intervals, and how that basis compares with research done by the Electric Power Research Institute (EPRI). It is our understanding that NERC did an industry survey of maintenance intervals and we would like to see the results of that survey as well. Specific comments: • Protective Relays – 6 calendar years is okay. • Voltage and Current Sensing Devices Inputs to Protective Relays – We question the logic for a 12-year interval. Proper functioning should be verified at commissioning, and then anytime thereafter if changes are made in a PT or CT circuit. Additional periodic checks may be warranted as suggested in Table 1A, however no additional checking should be required where circuit configuration will inherently detect problems with a PT or CT. For example, PTs & CTs that are monitored through EMS or microprocessor relays will be alarmed when they are out of specification. • Protection System Control Circuitry (Breaker Trip Coil Only) (except for UFLS or UVLS) – In locations where the continuity of the circuit is not monitored (via a light in the path or through a microprocessor relay) this would be a very complicated test, which could impact reliability, especially if done every three months. • Protection System Control Circuitry (Trip Circuits) (except for UFLS or UVLS) – Need clarity on exactly what the activity is to include. We believe proving one output all the way to the trip coil is appropriate. Proving every output and every auxiliary contact, to the trip coil would be unnecessarily invasive and could impact reliability, even if done every 6 calendar years. • Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only) – Interval is okay, but we disagree with tripping the breakers – proving the output of the relay should be sufficient. Systems that have all load shed on distribution circuits should require trip output be confirmed but should not be required through to the trip coil due to constraints in tying distribution load. • Station dc supply (that has as a component any type of battery) – 3 month and 18 month intervals are probably okay, depending on what is required to “verify continuity and cell integrity of the entire battery” and “inspect the structural integrity of the battery rack”. • Station dc supply (that has as a component Valve Regulated Lead-Acid batteries) – 3 calendar years and 3 month intervals are probably okay, depending on what is required for the “performance or service capacity test”. • Station dc supply (that has as a component Vented Lead-Acid batteries) – 6 calendar year and 18 month intervals are probably okay, depending on what is required for the “performance, service or modified performance capacity test”. • Protection system communication equipment and channels – 3 months and 6 calendar years seem reasonable, depending upon what is included in the substation inspection, and what is required for power-line carrier systems. • UVLS and UFLS relays that comprise a protection scheme distributed over the power system – Can’t comment on the 6 calendar year interval until we get more clarity regarding the meaning of “distributed over the power system”.
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
No
For utilities like us with large numbers of relays it’s too complicated, which drives us back to Table 1a.
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the standard.
Yes
We strongly believe that this document should be made a part of the standard, either as an Attachment or worked into the requirements and tables. This will bring clarity to PRC-005 that is needed to get away from all the past problems that were due to a lack of clarity with the previous PRC-005 standards. Also, all the explanations and guidance lose force if they are not part of the standard. Auditors will only be bound by the standard.
None
Regional Variance
Regions with ISO’s and RTO’s - Where the independent system operator (ISO) is not the same company as the entity doing testing and maintenance, the independent system operator could prevent the entity from performing scheduled maintenance and testing due to outage request constraints. There should be no violation in such a situation, and the maintenance and testing just rescheduled.
• Regarding the Implementation Plan, R1 compliance should be the first day of the first calendar quarter 18 months following applicable regulatory approvals. Entities will need this time to change monitoring equipment and develop extensive new work practices and procedures to assure time frames and documentation of practices comply with the wording of the revised standard. The time frames for R2, R3 and R4 are adequate except in cases where upgrades have to be developed and implemented in order to be able to meet the intervals (such as breaker trip coil verification every three months). • FAQ 2C “If I am unable to complete the maintenance as required due to a major natural disaster, how will this effect my compliance with the standard.” Response is the Compliance monitor will consider extenuating circumstances…We would like to see this statement clarified as to the time frame extensions that result in non compliance or fines. • R4 – States “each transmission owner…shall implement its PSPM, including identification of the resolution of all maintenance correctable issues”. If the intent is to document resolution to misoperations this is a reasonable request. If the intent is to document that a relay was found out of calibration on a routine test, which was corrected by recalibration we need some clarity on expectations of how that would be recorded and tracked. As written this statement is vague and somewhat confusing since % of allowable error may vary utility to utility. • R4 doesn’t appear to allow any time beyond the stated intervals for repairs or replacements that may take additional time. PRC-005-2 is a maintenance and testing standard, and R4 inappropriately requires a replacement strategy and an obsolescence strategy. Is R4 intended to apply to all equipment in Table 1?
Individual
Bob Thomas
Illinois Municipal Electric Agency
Yes
 
No
The Illinois Municipal Electric Agency (IMEA) is concerned the minimum maintenance activities may be too prescriptive for transmission subsystems that essentially operate radially. Please see comment under Question 7. Also, IMEA supports comments submitted by Florida Municipal Power Agency regarding applicability to UFLS systems.
No
IMEA is concerned the maximum allowable maintenance intervals may be too prescriptive for transmission subsystems that essentially operate radially. Please see comment under Question 7. Given the magnitude of reliability-related initiatives currently in progress, additional time is needed to evaluate these intervals, particularly for communications equipment, dc supply, and UFLS relays.
No
IMEA supports comments submitted by Florida Municipal Power Agency regarding use of the word “every” in Table 1c.
No
IMEA supports comments submitted by Florida Municipal Power Agency that the process outlined in Attachment A is biased towards larger utilities.
No
 
Yes
Under “Group by Type of BES Facility”, 1. (page 15) – The radial exemption in the BES definition should be clarified to include transmission subsystems within a single municipality, where the transmission facilities – serving only subsystem load with one transmission source - essentially operate radially. A more practical application of the radial exemption would address smaller TOs whose system has minimal potential to impact the BES as a whole.
 
 
 
Individual
Scott Barfield-McGinnis
Georgia System Operations Corporation
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
 
No
 
Not aware of any.
None.
None.
Group
Public Service Enterprise Group Companies
Kenneth D. Brown
Yes
 
No
1) Table 1a – Protection System Control Circuitry (Trip Circuits) (UFLS/UVLS Systems Only). Currently, we test our UFLS relays on a 2 year maintenance interval. We test the relays and associated DC circuitry up to the DC lockout relays. It would require extraordinary effort to trip the breakers directly when performing these tests. Usually, each UFLS relay will trip several feeder breakers. This requirement states that we need to check the trip coil for each of those breakers each time we perform relay maintenance. This will add an unreasonable amount of time and effort to reliably switch out several 4kV or 13kV feeder every time we perform UFLS maintenance. For UFLS and UVLS schemes, we feel the requirement for DC control testing should not go past the lockout relay. The standard says to perform trip checks at the same time as UF maintenance. We test the relays on a 2 year interval right now. It is unreasonable to perform trip checks this often. The trip checks should follow a 6 year span (or longer) just like the BES equipment. 2) Table 1a – DC supply. The 18 month inspection requires a measurement of specific gravity and temperature. We believe that if a battery owner opts to perform an 18 month ohmic value test, this combined with the cell voltage readings and continuity tests will give a good indication of battery health. We do not feel that the measurement of specific gravity is required in conjunction with the tests performed above.
No
1) Table 1a – Station dc supply (that uses a battery and charger). The 6 year test requires that the charger perform as designed. PSE&G usually applies redundant battery chargers. PSE&G would like the drafting team to consider if it is appropriate to not require the 6 year battery charger tests if a battery owner uses primary and backup battery chargers. PSEG believes that the use of a redundant charger will maintain reliability at the same level or better level as provided by testing a single charger. 2) For protection system control circuits components (breaker trip coil only), suggest that a sub category with redundant trip coils be added with longer maintenance interval to allow for the reliability provided by redundancy.
 
 
Yes
Figure 2 “typical generation system” shows a typical auxiliary medium voltage bus, suggest that a line of distinction (dotted line) be added to the figure that defines the element connected to the BES (station Aux Transformer - SAT) and equipment not associated with protection of the SAT be shown as not part of the BES- PSMP.
Yes
1) R1 - PRC-005-1 required the protection owner to supply a “basis” for the chosen maintenance intervals. Is it intended that the new standard will no longer require the protection owners to provide a basis for their intervals as long as they meet (or better) the published required intervals? 2) Compliance 1.4 Data Retention – Needs more clarity. Some items require 12 years maximum maintenance interval. However, we may perform the same maintenance in 6 years. The requirement for data retention is 2 maintenance intervals. In this example, does this mean 12 years or 24 years? Are we required to maintain records for the maximum maintenance intervals allowed by the Standard or only for the two shorter maintenance intervals that we actually use? 3) Compliance – will need some guidance on to what is required for “proper documentation”. Generally, the relay technicians will scribe the actual test values for a given tests requiring the application of AC voltage and current. However, as an example, when performing DC checks (DC aux relay), the technician may simply state that the aux relay is “OK” without stating the DC coil pickup value in volts. Is this acceptable? Another example may be when performing battery inspections (ie verify proper voltage of station battery, verify that no DC grounds exist, etc), the inspector may simply indicate/document that the battery is “Ok”. This would indicate that appropriate 3 month inspections (as per table 1a) were completed and found to be within tolerances. Is this acceptable? If specific details are required to be stored on test media (paper test sheets, computer based data storage, etc), then please make some comments as such. 4) Table 1a – DC supply. The 3 month inspection requires “verify that no dc supply grounds are present”. This needs further clarification. What is the defined “limit” to determine whether we have a DC ground? The detection methods for determining the presence of a DC ground will vary from indicating light balance to actual DC ammeters or voltmeters. It is assumed that the intent of this requirement is to ensure that there are no full DC grounds (dead shorts) in the DC terminals. Please clarify. 5) In the group by type of BES facility descriptions on pages 15 and 16 there is discussion about generation station auxiliary transformers and associated protection devices. It also cites examples of relays which need not be included even though they could result in tripping of the generating station. The line of demarcation is not well defined in the FAQs or in the standard itself. Suggest that verbiage be added that clearly defines the element (transformer) directly connected to the BES and it’s associated protection is what is included in the PSMP requirements, items connected at lower voltage (down stream) are not within the PSMP requirement. 6) On page 15, the sample list of what is included in the standard, suggest that the list be expanded to show what is not included (a relay that monitors parameters and is used for control/ alarm but not protection); generator excitation controls that trip an auxiliary exciter. The list of items not included in the PSMP but that could trip the unit should be further defined and expanded.
 
 
1) R4 requires all maintenance correctable issues identified as part of a time based maintenance plan to be resolved in that same maintenance period. This places a burden on some items (for example, 3 month battery inspections) to achieve adequate resolution for problems that are not an immediate threat. For example, if a battery with a somewhat out of allowable range specific gravity is found near the end of the maintenance period, scheduling and performing the work to replace the battery could reasonably extend somewhat beyond the end of maintenance period. PSE&G requests that the drafting team revisit this requirement and allow flexibility for corrections to be made within a specified reasonable timeframe when correctible issues are identified that for practical reasons require extension for work completion beyond the end of the current maintenance interval. 2) Section 4.2.5.5 of the standard should define provide an example that just the transformer connected to the BES is included and specifically exclude connected equipment beyond the LV terminals. 3) Draft implementation plan for requirements R2, R3 & R4 discusses table 1a as basis, should also address tables 1b and 1c.
Individual
Jianmei Chai
Consumers Energy Company
Yes
 
No
The second sentence in Note 1 on page 20 should be changed to “A calibration failure is when the relay is inoperable and cannot be brought within acceptable parameters.” Note 2 should be changed to “Microprocessor relays typically are specified by manufacturers as not requiring calibration. The integrity of the digital inputs and outputs will be verified by applying the inputs and verifying proper response of the relay. The A/D converter must be verified by inputting test values and determining if the relay measurements are correct.”
No
The interval for Protection System Control Circuitry (breakers trip coil) should be set at 12 years since this is a scheme test. This test requires testing of the circuit and not just the coil. The interval for Protection System Control Circuitry (trip circuit) should be set at 12 years since this is a scheme test. The Protection System Control Circuitry (trip circuit) test would require tripping off customers on radial distribution circuits which is not acceptable. The interval for a station battery service test (lead acid) should be set at 5 years based on NFPA 70B.
 
 
 
 
 
 
In Table 1a for Station dc supply it requires verification that no dc supply grounds are present. DC grounds are common occurrences and the activity should be to document if dc grounds are present. Please specify how cell to cell connection resistance is measured. For station dc supply (battery is not used) change “Verify the continuity of all circuit connections that can be affected by wear and corrosion” to “Inspect all circuit connections that can be affected by wear and corrosion.” Is “metered and monitored” equivalent to “alarming”? If a component failure causes the unit to trip, what is the purpose of testing it? It will always test positive until the point of failure and that point is identified when the unit trips. In the Facilities Section 4.2.5.4 “station service transformer” should be changed to “unit connected auxiliary transformer” to be consistent with Figure 2 of the Supplement Reference Document. Facilities Section 4.2.5.5 should also include “System connected auxiliary transformers are excluded when only used for unit start-up.” There should be an allow variance period (grace period) for the testing intervals. The maximum allowable time periods should be in calendar years, defined as “occurring anytime during the calendar year.” The following statement should be added to Requirement 1.2: “Identification at a program level is permissible if all components use the same maintenance method.”
Individual
Vladimir Stanisic
Ontario Power Generation
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
A well prepared and useful document.
No
It was a good idea to prepare such a document.
Not aware of any
Regional Variance
Maintenance activities, and especially intervals, prescribed in NPCC Directory 3 (Maintenance Criteria for BPS Protection) often differ from those in PRC 005 - 02. We recommend that NPCC aligns Directory #3 with PRC 005 - 02 as much as possible. Technical justification should be provided for any variance.
We note that Verification of Voltage and Current Sensing Device Inputs to Protective Relays is a somewhat ambiguous activity. NERC’s audit observation team came up with a similar finding. The supporting documents provide some clarity but in our opinion it would be helpful if the SDT could elaborate this activity in more detail in the Table itself.
Group
Bonneville Power Administration
Denise Koehn
Yes
 
Yes
 
Yes
 
Yes
 
 
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
Will this document be a part of the standard? Are its explanations the official interpretation of the standard?
 
 
1. Tables 1a, 1b, and 1c were cumbersome to use because we found ourselves flipping back and forth to compare the requirements for the different levels of monitoring. Also, in some cases, the types of components were slightly different between the tables, which created confusion. We believe that it would be much easier to decipher a single table that listed each type of component only once and showed the requirements and maintenance intervals for the different levels of monitoring on a single page. Even if it took an entire page for each component, it would be very useful to see all of the options for that component without having to flip back and forth between tables. 2. Please clarify the requirements for trip coils. Table 1a has as a component type "breaker trip coil only", with a maximum maintenance interval of 3 months, while Table 1b has as a component type "trip coils and auxiliary relays". Table 1b say that there are no monitoring attributes for this component and to use the level 1 intervals, but then gives a maximum maintenance interval of 6 years, which doesn't agree with the 3 month interval given in Table 1a. 3. The terminology used to describe the secondary currents and voltages provided to the relay is confusing. Under the modified definition of a protection system, it includes the term "voltage and current sensing inputs to protective relays", and in the tables it uses the term "current and voltage circuit inputs". These terms, especially the use of the word input, give the impression that the actual input circuitry of the protective relay is what is being described, but we believe that these terms are really meant to describe the secondary currents and voltages from the instrument transformers (or other devices). BPA suggests revising the terminology to describe the secondary currents and voltages. For example, in the maintenance activities section of the tables, you could say, "Verify that the secondary current and voltages provided to the relay are correct". 4. There is no mention to what the thresholds are when performing these maintenance activities or what corrective actions must take place and by when they need to be carried out. Is this something we should expect to see soon? 5. The need to measure the cell/unit internal ohmic value every 18 months can be argued. BPA’s Substation Maintenance crew performs these measurements once every 24 months and with the Operators monthly inspections, we have been able to effectively catch any problems before a severe event/failure. 6. Communications: It is not clear specifically what equipment is included in "communications". The test interval of 12 years in table 1b is too long to verify continued proper operation of transfer trip tone equipment. Monitoring the presence of the channel does not provide any indication of whether the equipment can initiate a trip. Consequently, a required minimum interval of 12 calendar years is too long and does not do anything to verify proper communications support of the relay scheme. A shorter interval of 6 years, such as that in table 1a makes more sense from a functionality standpoint.
Individual
James H. Sorrels, Jr.
AEP
Yes
 
No
In the process of performing maintenance, some protection systems may need to be taken out of service on in-service equipment (bus differential protection for example) where redundant protection systems do not exist. This action seems counter to NERC recommendations, presenting a scenario for expanding outages during a simultaneous fault. Would the implementation plan include time for the additions of redundant protection systems? Comments expanded in question 10 response.
No
The availability to perform maintenance of many protection systems is dictated by the load or customer that is connected. Many of these industrial customers, who are outside the jurisdiction of NERC requirements, operate 24X7 and see the outages required for maintenance as a nuisance and a loss of revenue. How can the owner be held non- compliant for not meeting the intervals when they may not control the timing? Comments expanded in question 10 response.
No
How would the failure of a SCADA system affect the ability to take advantage of monitoring?
 
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written so that multiple, lengthy supporting documents are not needed. These supporting documents do not get recorded into the registry as part of the standard and may or may not be used by auditors during compliance audits which could lead to different interpretations.
Yes
Although helpful in understanding and clarifying intent, the requirements of a standard should be clearly written so that multiple, lengthy supporting documents are not needed. These supporting documents do not get recorded into the registry as part of the standard and may or may not be used by auditors during compliance audits which could lead to different interpretations.
No known conflicts.
No none regional or business practice variances known.
Monitoring and tracking the activities prescribed in the standard seem too complex to manage at a level needed for auditable compliance. The activities prescribed seem to lean toward conventional protection systems and do not take into account newer special technology devices (High Voltage DC, Static Var Compensator and Phase Shifting transformer controls) and how there are to included. R1 1.2 Does the draft standard require a basis for an entities’ defined time based maintenance intervals or can an entity just move directly to the intervals prescribed and use the standard as its basis? R4. This requirement seems to refer to failed equipment and its’ reporting. This corrective maintenance activity is outside of the interpreted preventative maintenance theme of the standard and adds another layer of complexity in compliance data retention. It also implies that a failed piece of equipment or segment could remain failed for the entire maintenance interval. Tables 1a & 1b. Station dc supply (that has as a component any type of battery) Interval: 18 months This requirement incorporates specific gravity testing (where applicable). Although (where applicable) is not defined, it seems it refers to all non-sealed batteries. For sealed batteries, a more frequent internal ohmic test is prescribed. The same 18 month requirement incorporates ohmic testing which is essentially equivalent to specific gravity. Specific gravity and measure of internal temperature are invasive tests which subject personnel to handling acid and subject the battery to damage. If the logic for sealed batteries is to do more frequent ohmic testing why not allow more frequent ohmic testing as a substitute for specific gravity? We would suggest ohmic testing every 6 months with any questionable results rechecked using specific gravity. This eliminates excessive intervention into all cells and gives a validity check on the ohmic testing. For Ni-Cad the performance service test has no option (6 year intervals). Typically, the Ni-Cad can yield a low voltage indication; however testing the cells in pairs allows testing and finding bad cells. Why not offer a more frequent ohmic test for the Ni-Cads? Facilities 4.2.1 and R1 ‘…. applied on, or are designed to provide protection for the BES.’ This may be in conflict with Regional Entity (RE) BES definitions. There needs to a clear understanding of what is included and what is not without regional differences. There should be no responsibilities or requirements of the RE. BES also takes on different meanings depending upon which of the many standards it is applied. Data Retention 1.4 Data retention for two intervals could mean that records would need to be kept for 24 years. This seems impractical. Could audit evidence be used in lieu of actual data for long intervals? Tables: Where the interval is in months, the term ‘calendar’ months should be used for clarification. Table 1a ‘….verify the continuity of the breaker trip coil…..’ The SDT assumed that Trip Coil Monitoring (TCM) could be accomplished by verifying/inspecting red lights. This may be true in most cases, but there are designs that do not incorporate this type of TCM and the breaker would have to be exercised every 3 months if not operated by natural events unless the scheme gets replaced. This seems counter productive to the reliability of the BES. The implementation plan does not take the time required for upgraded systems into consideration. Table 1a DC Supply, 3 month interval ‘Verify no dc supply grounds are present.’ Does this mean that you are non-compliant if you have a DC ground? This also needs to be clarified as to the amount of acceptable ground that could be present. Table 1a PS communications equipment channels 3 month interval: Do the activities imply that only alarms be verified and that no channel ‘playback’ be performed? If SPR relay or similar auxiliary relay is excluded as a protective relay, then do we not have to verify its tripping contact as part of the DC system? Table 1a The exclusion of UVLS/UFLS from certain activities is confusing. Does trip coil monitoring not have to be performed on these systems? Tables: Since PT and CT devices themselves are not included in the PS definition, then the word ‘devices’ should be removed from the type of component column describing inputs to the relay. Table 1a. Even though an entity may be on time-based intervals, would a natural occurring fault event reset the maintenance clock for the protection segment involved? Assessment of Impact of Proposed Modification to the Definition of Protection System: Reclosing and certain auxiliary relays have been excluded from protection system definition. This new definition would have an impact on other PRC standards that use this term in its requirements, specifically the misoperations investigation and reporting standards. These other standards, as written today, are not clearly written as to the application and assumptions as to what is included in a protection system. Trip coil Monitoring: If the trip coil is actually part of the DC circuitry, then why is there a differing (shorter) interval for this series connected element?
Individual
Jason Shaver
American Transmission Company
Yes
 
No
The Standard should focus on identifying the types of components to be tested but should not identify the specific maintenance activities that must be performed. Entities should be allowed the flexibility to develop and implement the appropriate maintenance activities necessary for each identified component. ATC is also concerned with the expressed identification of maintenance intervals. We do not believe that the standard should identify specific maintenance intervals but that it should require entities to identify their maintenance intervals appropriate for their system. If the team continues to pursue specific maintenance intervals it will be establishing the industries practices. Specific Concern: The standard identifies that entities should perform complete functional testing as part of its maintenance activities, but we are concerned that this could lead to reduced levels of reliability, because it requires entities to remove elements from service and then requires entities to perform tests that are inherently prone to human errors. We believe that the perceived benefits do not match the anticipated costs or improve system reliability.
No
ATC is concerned that the proposed standard would result in entities being required to use outdated testing techniques and or practices. We believe that the standard should identify the “what” and not the “how”. The identification of specific testing techniques and/or practices would likely result in entities being prevented from implementing improved techniques and/or practices. (The standard would have to be updated and receive FERC approval before entities could test/implement improved testing techniques and/or practices.) And example of the standard directing the how is with station batteries. The “specific gravity” test, proposed in the standard, is being used less or not at all by some registered entities because a more accurate method that is less intrusive and provides more accurate results has been developed. (This standard would basically require entities to go backwards in testing practices.) This standard should not prevent the use of improved techniques and/or practices.
No
ATC does not believe that there is a relay, on the market today, that has the ability to fully monitor itself as described in Table 1c. We believe that Table 1c should be deleted. (Table 1b could cover any device that has the ability to fully monitor if such a device is developed in the future.) ATC does not believe that NERC Reliability Standards should be used as an enticement for manufacturers to develop specific devices. Under the “General Description” in Table 1c, there is a reporting requirement identifying a 1 hour window. (“… must be reported within 1 hour or less of the maintenance-correctable issue occurring, to the location where action can be taken.”) ATC believes that the team needs to define if this action is a phone call or physically verify the maintenance correctable issue which is occurring.
No
ATC agrees with this approach but is concerned that Attachment A does not contain enough language to support an entity that implements this practice. This attachment needs to clearly state that following your performance-based maintenance practices satisfies an entity’s compliance obligations. Entities should not be subject to non-compliance over disagreements with their performance-based maintenance methodology.
No
 
No
Overall, the FAQ’s are helpful. Explanations for questions dealing with the maintenance activities (e.g., battery testing) indicate an attempt to line up the requirement with IEEE standards. While commendable to attempt alignment with the industry, it is further justification that maintenance activities should not be included in the standard. Over the long term, technology or IEEE standards could change making the compliance standard inconsistent.
Order 672 says that standards should be clear and unambiguous This proposed standard is very complex. While the standard allows entities to select the appropriate maintenance strategy (time based, performance based or conditioned based) for their system the amount of data and tracking required to demonstrate compliance will be overwhelming.
Business Practice
Jointly-owned facilities should be a component of this standard. Comments: ATC shares services at Substations; consider dividing the services, i.e. batteries and PTs.
General Comment: The requirements section of the standard seems acceptable. NOTE: Why does R1.3 identify the inclusion of batteries? We believe that this should be part of the definition. We believe that the team needs to define the term “condition-based”. Does the Protection System definition in PRC-005-2 or interpretation of the standard and the tables line up with other NERC Standards? The table formats (1a through 1b) are confusing and should be reconsidered. We found is difficult to relate one table to another. (No consistency in the Type of components)
Individual
Edward Davis
Entergy Services, Inc
Yes
 
Yes
 
No
A 3 month interval activity is likely to drive an entity to perform that activity every 2 months in a zero tolerance, 100% completion, mandatory compliance environment. There should be an allowance for a grace period on monthly designated activities, for instance a one month grace period, unless the intention is to have the activity performed more frequently than indicated. Additional guidance is needed on the monthly interval designations. Is it okay, for instance, to do all four tasks (3 month interval) at one time? Instinctively the answer should be "no", but if following the "calendar year" allowance, then maybe it is. Are we non-compliant on a 3 month interval task if we go one single day over the due date? Instinctively the answer should be "no", but some additional guidance should be provided. For example, the standard might be more understandable if it indicated that if the interval is "four per year" (or 3 month interval), then it is allowed to perform these tasks no less than 45 days apart from each other as long as four are done within a calendar year, etc. We believe the 3 month trip coil task activity could actually shorten the life of the trip coil, introduce unpredictable trip coil failures, and increase the risk of an in-service failure of the trip coil if the verification is done by tripping the breaker each time. Increasing the risk of failure is counter-productive the intent of the standard.
Yes
 
Yes
 
No
Regarding Section 2.3, Applicability of New Protection System Maintenance Standards, there needs to be clarification and examples of applicable relaying associated with the language: “… and that are applied on, or are designed to provide protection for the BES.” For example, is the application of reverse power schemes and directional overcurrent schemes considered applicable when considering the impact to the protection of the BES? We agree with the application of the term “calendar” in the PRC-005-2 Protection — System Maintenance Supplementary Reference document. There should be enough flexibility in interval assignments to allow for annual maintenance planning, scheduling and implementation.
Yes
 
 
 
It would be beneficial to also include an explanation or definition of the term “calendar year” in the standard. It is not readily apparent in the draft standard, especially in light of the new maximum interval requirements, that a task can be performed anytime between 1/1 and 12/31. Although addressed in the FAQ and Supplement, the terms “Upkeep” and “Restoration” are referenced in the definitions section of the standard but are not used anywhere else in the document, or with regard to routine activities. They should be eliminated from the standard unless there are upkeep or restoration requirements.
Individual
W. Guttormson
Saskatchewan Power Corporation
Yes
Saskatchewan would like clarification of what the expectations and rationale are for including Restoration in the PSMP. The other terms listed under the PSMP definition represent what we would consider as typical relay maintenance activities. We would typically consider Restoration as an Operational activity. The existing NERC standards seem to treat this an Operator concern addressed in PRC-001 R2.1 and R2.2 (The Operator shall take corrective action as soon as possible). If Restoration is included in PRC-005 doesn't PRC-001 have to be modified as well to remove these references? Saskatchewan would also like clarification on the term upkeep. Is the standard prescriptive and mandate the application of the latest firmware upgrades within a defined period, or is it flexible and can upgrades be applied as the utility deems necessary?
Yes
 
Yes
 
Yes
 
No
Saskatchewan agrees with the approach, but requires clarification in the definition of segment. The definition uses a population of 60 or more individual components but in the establishment of a PSMP, it only asks for a population of 30 or more. Which number will be used to define the segment?
Yes
The supplementary reference document is useful information if properly explained and justified. Are the suggestions in the reference document to become part of the standard, or simply recommendations of best practice from industry and serve as a document to reduce the number of interpretations requested?
Yes
The FAQ section is beneficial, but would suggest reviewing it to determine if it can be integrated within the reference document.
 
 
Saskatchewan recommends that the PC's and RC's designate what equipment is applied to protect the BES and should be included in the protection maintenance program. It is questionable whether the facility owners or Distribution Providers will know. What are the impacts on the BES from the protection systems identifed in Facilities 4.2.5 and the FAQ? For example there is an impact on the BES from generator under-frequency protection not being properly coordinated, but assuming it is and if it is not maintained isn't the impact to the unit itself? Inadvertent energization protection also seems to be an impact to the unit itself not the BES? The standard should be concerned with protection systems that impact the BES not equipment protection that has localized impacts however important they may be. Change Facilities 4.2.2 to “Protection System components used for under-frequency load-shedding systems which are installed to prevent system under-frequency collapse for BES reliability.” The reference to ERO is unnecessary and inappropriate.
Group
FirstEnergy
Sam Ciccone
Yes
Although we agree with the change in the title of the standard, as well as the proposed definition of "Protection System Maintenance Program", we feel that the definition could be clarified. With regard to "Restoration", which at present is described as "The actions to restore proper operation of malfunctioning components", it may be helpful to add examples of acceptable actions to restore operations, such as calibration, repair, replacement, etc.
No
In general we agree with the maintenance activities, except for the specific gravity and temperature testing included in the "Station dc Supply (that has as a component any type of battery)" of the tables 1a and 1b. We only perform this testing at nuclear facilities for insurance requirements. In transmission substation applications it has been eliminated due to the variability of results due to recharging/equalizing, water addition, temperature correction requirements, etc. In the Supplementary reference, section 15.4 Batteries and DC Supplies, third paragraph, the SDT indicates these tests are recommended in IEEE 450-2002 to ensure that there are no open circuits in the battery string. This is essentially a continuity check of the battery string. In the fourth paragraph, the SDT states that "…"continuity" was introduced into the standard to allow the owner to choose how to verify continuity of a battery set by various methods, and not to limit the owner to the two methods recommended in the IEEE standards." The SDT in Table 1a, the Maintenance Activity "Verify continuity and cell integrity of the entire battery", and in Table 1b, the Maintenance Activity "Verify electrical continuity of the entire battery". Based on the information in the Supplementary reference, the owner has to choose a method to verify continuity and the measurement of specific gravity and cell temperatures could be the selected method, however it should not be a required maintenance activity as shown in Tables 1a and 1b.
No
Although we agree with the proposed maintenance intervals, there may be extenuating circumstances beyond an entity’s control that could delay maintenance on a particular protection system. We ask the SDT to consider adding a footnote to these intervals that allows a grace period of up to three months when outages necessary for maintenance must be delayed due to unusual system conditions or other issues where an outage would be detrimental to the entity's system.
Yes
 
Yes
Although we agree with the parameters of the proposed PBM, we have the following comments: 1. We question the inclusion of misoperations in countable events as described in footnote 4. Since standard PRC-004 already requires analysis and mitigation of Protection System Misoperations through a Corrective Action Plan, entities should not be required to repeat this analysis and mitigation in PRC-005. We ask that the SDT clarify the requirements to allow a tie between PRC-005 and PRC-004 so as to assure work is not duplicated. 2. We are not receptive to using this methodology to develop intervals due to the detailed tracking and analysis that will be required to establish maximum intervals. The approach may suit other utilities and thus, we are not opposed to the methodology being contained within the standard.
Yes
1. Sec. 2.3 (pg. 4) – This section appears to be discussing the purpose of the standard and not the applicability. We suggest changing the title of Sec. 2.3 to "Purpose of New Protection System Maintenance Standard." Also, in Sec. 2.3 it states: "The applicability language has been changed from the original PRC-005: '... affecting the reliability of the Bulk Electric System (BES) ...' To the present language: '... and that are applied on, or are designed to provide protection for the BES.' However, the posted Draft 1 of PRC-005-2 still has the original Purpose statement. Is the SDT planning to revise the Purpose statement as discussed in Sec. 2.3 of the Ref. document? It appears that this statement is included in the applicability section 4.2.1 but believe it is more appropriate as a general purpose statement applying to the whole standard. 2. Sec. 2.4 (pg. 4) – Remove the extra word "that" from the second sentence of this section. 3. In the Supplementary reference, section 15.4 Batteries and DC Supplies, third paragraph, the SDT indicates these tests are recommended in IEEE 450-2002 to ensure that there are no open circuits in the battery string. This is essentially a continuity check of the battery string. In the fourth paragraph, the SDT states that "..."continuity" was introduced into the standard to allow the owner to choose how to verify continuity of a battery set by various methods, and not to limit the owner to the two methods recommended in the IEEE standards." The SDT in Table 1a, the Maintenance Activity "Verify continuity and cell integrity of the entire battery", and in Table 1b, the Maintenance Activity "Verify electrical continuity of the entire battery". Based on the information in the Supplementary reference, the owner has to choose a method to verify continuity and the measurement of specific gravity and cell temperatures could be the selected method, however it should not be a required maintenance activity as shown in Tables 1a and 1b.
Yes
Pg. 17 (What forms of evidence are acceptable) – Although Measures are not yet developed and posted with the standard, we wanted to point out that the SDT should consider adding these acceptable forms of evidence in the measures of the standard.
 
 
1. BES reclosing schemes were recently questioned in a PRC-005-1 interpretation but there is no mention of reclosing schemes in the draft standard. This interpretation should be integrated into the requirements of PRC-005-2. 2. Lack of Exception Process - The standard as written does not reflect the fact that any one group, such as a TO performing maintenance on a BES, does not have full control over when an outage can be taken to perform maintenance activities. Especially regarding functional testing, where the equipment needs to be exercised resulting in some BES components being de-energized, it can be very difficult in certain parts of the T&D system to obtain the necessary outage to complete these tasks. Even with proper planning, changes in system conditions and unforeseen equipment problems in other areas can impact the ability to schedule an equipment outage appropriately. Accordingly, a TO can be penalized for not completing prescribed maintenance within prescribed limits due to factors outside of their control. This type of scenario has already been experienced where maintenance activities are scheduled upwards of a year in advance, and then inclement weather or system conditions outside of a TO’s service territory (e.g. unanticipated generating unit shutdown) prevent the work from taking place. The standard should provide some specific guidance to allow relief for such situations, or that properly incents or even requires independent system operators (ISOs) and other outside groups to also ensure maintenance is completed within prescribed intervals. If a TO properly considers factors such as weather (not scheduling critical outage during middle of summer), resource commitment, schedule (the requested outage window is at least one year before maximum interval is met), time of day (performing work during after hours period when load is down) etc. then if outages are still denied, that the TO is not penalized for being out of compliance as maximum intervals are exceeded. This suggested "exception process" should provide requirements for all parties involved, both those performing the maintenance as well as those controlling and overseeing the system. There should be required documentation to prove that the parties on both sides made proper efforts to complete the required maintenance, as well as discuss conflict resolution. 3. With regard to the phrase "including identification of the resolution of all maintenance correctible issues" in Req. R4, we feel that this requirement should be a subset of R4 since it is part of the implementation of the PSMP. We suggest removing the phrase from the main requirement of R4 and creating a new 4.3 as follows: "4.3. For all maintenance programs, identify resolutions for all encountered maintenance correctible issues and take corrective action within a time period suitable for maintaining reliability of the affected protection system." 4. With regard to the proposed modification of "Protection System", we suggest adding the word "devices" after "voltage and current sensing". This would also match what appears to be the SDT’s intended wording as shown in the Supplementary Reference Document sec. 2.2. Also, we suggest modifications to the proposed definition to add clarity to the types of communications system protection and the voltage and current sensing devices. The following is our suggestion for wording of the definition: "Protective relays, communication systems used in communications aided (or pilot) protection, voltage and current sensing devices and their secondary circuits to protective relays, station DC supply, and DC control circuitry from the station DC supply through the trip coil(s) of the circuit breakers or other interrupting devices." 5. Protection System Communication Equipment and Channels - Some power line carrier equipment has automatic testing and remote alarming and some that does not. For other relay communication schemes (e.g., tone transfer trip ckts), if the circuit travels over our private communications network (fiber or microwave radio), the communication equipment is remotely monitored/alarmed. In other cases it is not remote monitored. We ask for clarification as follows: As part of our maintenance program, we check that signal level, reflected power, and data error rate are all within tolerance at the interface between the end equipment and the communication link. Our question is: Does this meet the intent of the proposed requirements in PRC-005-2 for maintenance activities for Protection System Communication Equipment and Channels? Or do the requirements ask for something beyond this? 6. We suggest combining 4.2.2, 4.2.3 and 4.2.4 to read as a new 4.2.2 "Protection System components which are installed as a underfrequency load shedding, underfrequency generation shedding, under voltage load shedding or Special Protection System for BES reliability."
Individual
Alice Murdock
Xcel Energy
Yes
 
No
Regarding battery chargers, does the SDT propose that OEM-type tests be performed to validate the rated full current output and current limiting capabilities? It has been proposed that simply turning off the charger and allowing the batteries to drain for a period of several hours, then returning the charger to service, will validate these items. It is not clear that an auditor would come to the same conclusion, since it appears open to interpretation. Please modify to make this clear. If an entity has an over-sized battery charger, they can (and should) only test to the max capacity of the battery bank. Suggest changing “full rated current” to “designed charging rate”.
No
Within the tables, several components related to UFLS/UVLS systems have an interval of “when the associated UVLS or UFLS system is maintained.” Yet, there is no maximum interval established for a UVLS or UFLS system. We feel this item should be clarified. If the intent of the SDT is to tie the testing to when the UFLS/UVLS relays are maintained, so that all components are tested at the same time, then this should be made clear. One possible resolution would be to change the interval to read: “when the associated UVLS/UFLS relays are maintained”.
Yes
 
Yes
 
Yes
The information in the supplementary reference document is very helpful and valuable. Yet, it is not clear how the document would be managed/revised, nor what role it plays in compliance monitoring. There needs to be a clear understanding if everything in the document is required for compliance, e.g. criteria for monitored systems, etc. Additionally, we feel that evidence should be addressed within the supplementary reference document.
Yes
The Frequently-asked Questions seem to act as interpretations to the standard. What roll will they play in determining compliance? On table 1b (page 11) the UFLS and UVLS maintenance activities indicate that tripping of the interrupting device is not required, but it uses the term ‘functional trip test’. The FAQ indicates that a ‘functional trip test’ does require tripping the interrupting device. This conflicts with what is in the table and should be corrected in the FAQ to reflect that no trip is required.
 
 
Please clarify if the following are subject to PRC-005-2 requirements: 1) a battery that is in a station where the only BES element is a UFLS scheme 2) batteries used only to support communication elements (microwave houses)
Group
NERC Standards Review Subcommittte
Carol Gerou
Yes
N/A
No
A. In the tables, the term “verification” should be switched with “check”. B. The verification activities include testing for “specific gravity” in batteries. Since “impedance testing” will give you the same results or similar results; revise the tables to reflect this, as well. C. Another question deals with the table title verbiage. Table 1a and 1c are labeled as Protection Systems, while Table 1b is Protection System Components. One could interpret table 1c as saying that if any one component of the protection system in question is not in compliance with level 3 monitoring stipulations, then every component must be degraded to level 2 monitoring as so forth. This needs to be clarified. D. Some activities, such as complete functional testing, could lead to reduced levels of reliability, because [1] it requires removing elements of the transmission system from service and [2] it requires performing tests that are inherently prone to human errors. The MRO NSRS does not believe the perceived benefits justify the anticipated costs. E. In the tables, under Table 1a and Protection system communications equipment and channels, a technical justification should be provided to show that performance and quality channel testing would result in the reduction of regional disturbances and blackouts. Quality and performance testing is subjective. Subjective tests are inherently poor compliance measures. The requirements to measure, document, store, and prove channel quality data is a poor use of limited compliance resources. F. In the tables, under Table 1a and Station DC supply (and anywhere else), equalize (battery) voltages should be eliminated. Equalizing battery voltages reduces battery life and do not provide a significant gain in overall system reliability to offset the loss of battery life. G. In the tables, under Table 1a and Station DC supply (and anywhere else), delete the reference to measuring the fluid temperature of “each cell”. A technical basis should be demonstrated that shows why individual cell fluid temperature measurement would reduce the occurrence of regional disturbances. If fluid temperature measurement remains in the standard, a single fluid temperature measurement per battery bank should be sufficient to demonstrate that the battery bank was performing within normal parameters. The compliance burden to add fluid temperature measurements for each cell is unwarranted and reduces compliance personnel resources that could be utilized on more important reliability activities.
No
A. It looks like for unmonitored systems, breaker trip coils are to be checked for continuity every 3 months. There is no mention of auxiliary relays. In the partially monitored and fully monitored sections, trip coils and auxiliary relays are lumped in the same category at 6 calendar years each. What happened to the aux relays in the unmonitored section? Also, note that the term "trip coils" is used, not "breaker trip coils" in the type of component category. B. The maintenance interval for Protection System Control Circuitry (Trip coils and Auxiliary relays) is 6 years, but the interval for relay output contacts is 12 years when these components are partially monitored. It seems that these things all have a similar reliability. If commissioning tests are done diligently, the trip DC availability is continuously monitored and the trip coil itself is continuously monitored, no functional tests should be needed. The only thing that would be done at PM time would be to ensure that the alarming method is still functional.
Yes
A. The MRO NSRS agrees with this approach; however, I think most entities will not see the advantage of condition-based maintenance until they can resolve any gaps in data retention. If an entity was retaining a set of maintenance records but failed to include all the needed information as specified in this standard so they would need to adjust their maintenance procedure to collect all information and then they would need to wait for the entire retention period until they could start using the extended maintenance interval. If an entity had a collateral set of records which verified the information that lacked in the original maintenance record then could the entity start using the extended maintenance interval? For example, an entity has records showing that they have maintained a voltage or current transformer within the prescribed maintenance interval listed in level 1 monitoring (which is a maximum 12 year maintenance interval). Could this same entity go to level 3 monitoring (which is a continuous maintenance interval) immediately if it can query their SCADA and produce detailed records indicating the accuracy of the PT or CT for the maintenance records already retained? B. For lockout relays, if commissioning tests are done diligently, the trip DC availability is continuously monitored and the trip coil itself is continuously monitored, is it necessary to operate these relays for functional testing? For breaker failure lockout relays, re-verifying the operation of the coil and all the contacts could mean taking multiple breakers and line terminals out of service at the same time. Functional trip tests could cause unintentional tripping of equipment, cause equipment damage and interruption of service to customers. It's hard to see how the reliability of the BES is significantly improved by doing this test. The MRO NSRS feels the risk of adverse impact could be greatly reduced by a longer interval such as 12 years. C. In table 1c, the word “continuous or continuously monitored” is used. Please clarify the “within 1 hour” time frame takes into account that there may be a communication outage (failover) that will prevent an entity to “continuously” monitor a device.
No
A. The MRO NSRS is concerned that this approach could lead to non-compliance if the company follows this process and a Compliance Auditor disagrees with the method that was used. An applicable entity should be protected if they follow the standard appropriately. There should be some assurance of a grace period for mitigation if this selected approach was not accepted. B. Please provide the basis for having at least 60, then taking 30 (50%) for testing/maintenance. This may give an unfair advantage to larger companies rather than being fair across the board. This places an undue burden on smaller companies by having to team up with other asset owners.
No
N/A
No
Overall, the FAQ’s are helpful toward understand what the SDT was thinking. Explanations for questions dealing with the maintenance activities (e.g., battery testing) indicate an attempt to line up the requirement with IEEE standards. While it is commendable to attempt alignment reliability standards with other industry standards, it also begs the question of why requirements that are already covered by other standards should be repeated in reliability standards. In addition, if the other standards are changed, then they could become inconsistent with or contradictory to the reliability standard.
Conflict: Order 672 says that standards should be clear and unambiguous.
 
A. In the applicability section 4.2.5.5, change the statement to say, “Protection systems for BES connected station-service transformers for generators that are part of the BES.” B. In the applicability section 4.2.5, change the statement to replace “are part of” with “directly connected to”. The “are part of” will be left to interpretation. Please indicate the added reliability benefit by collecting this in Table 1a Page 9 protection system communication equipment and channels. C. If a breaker failure relay is also being used for sync-check, is it required to verify the voltage inputs since they are used for a closing function and not a tripping function? It is understood that the current inputs would have to be verified since these are used for breaker failure tripping. D. Please clarify requirement R1-1.1, does one have to individually list out each Protection System and its associated maintenance activities or can the PSMP be a generalized procedure that covers each of the components in all of a utility's Protection Systems? E. All references to breakers should be eliminated; thus, eliminate breaker trip coils. Breakers are primarily mechanical in nature and should be excluded similar to mechanical relay systems such as sudden pressure relays. F. Clarify that trip coils checks or tests can be verified through alternate means other than physically tripping the coil or potentially requiring system outages to physically trip a coil. Alternate tests could consist of checking self monitoring relays, continuity lights, etc. Trip coil tests could require transmission line outages which can be denied by regulatory authorities due to system conditions beyond an entity’s control. Significant delays of months or longer could occur to obtain a transmission line outage. Further, potentially requiring transmission line outages for trip coil test could harm BES reliability by increase the number of force transmission line outages due to testing. System reliability could be significantly negatively impacted anytime testing on trip circuits is performed due to human errors causing outages or regional disturbances. G. One item R1.3 (inclusion of batteries) was questioned as why this was specifically called out. It should be part of the definition. H. Define the term “condition-based”. I. The format of the tables is poor with 17 line items addressed in each. It is difficult to relate one table to another because they are not consistent with regard to the type of components. For example table 1a references of components a “breaker trip coil (only)” and the 1b references “trip coils and auxiliary relays”. J. R1.1 please add “… as they apply to the applicable entity”. As stated now, all three tables must be accomplished. K. Please add the words “time based maintenance methods” to table 1a for clarity in the heading. L. Table 1b under general description, last sentence the word “elements” should be replaced with “maintenance activities” which will provide exactly what is intended. M. Table 1b, if maintenance activities for level 2 monitoring include level 1 maintenance activities, then redundant activities in table 2 that are contained in table 1 should be removed (the same for table 3 to table 2 to table 1). N. If an entity maintenances a protective relay such that it is included in level 2 monitoring (a Condition Based Maintenance program) and this relay is considered to have a maximum interval of 12 years, does the entity need to also perform the maintenance activities for level 1 monitoring since the table 1b header indicates, “General Description: Protection System components whose alarms are automatically provided daily (or more frequently) to a location where action can be taken for alarmed failures. Monitoring includes all elements of level 1 monitoring with additional monitoring attributes as listed below for the individual type of component?”
Group
Platte River Power Authority Maintenance Group
Deborah Schaneman
Yes
 
No
Minimum maintenance activites should be based on categorization of relays and defined maintenance actions system by system using historical and definitively known data entity by entity. By establishing specific minimum maintenance activities you risk entites changing currently effective maintenance programs to programs that match minimum maintenance activities to meet requirements in the Standard which could be less effective for their system.
No
Electro-mechanical relays are historically out of tolerance well before the 6 year maximum allowable maintenance intervals defined witin table 1a.
Yes
 
Yes
 
Yes
It isn't clear in the Supplementary Reference Document why lock-out relays (86) are included as a component of Protection Systems that require a 6 year maximum interval. Historically we haven't experienced any failures with lock-out relays and feel the risk of causing a system reliabiliy issue by removing it from service and restroing it far out weghts the benefits of testing it. What, if any evidence, i.e. equipment failure, does the standard drafting team use to mandate routine testing of 86 devices? Are we fixing something that isn't broke here? The FERC order directed NERC to submit a modification to PRC-005-1 that includes a requirement that maintenance and testing of a protection system be carried out within a maximum allowable interval that is appropriate to the type of the protection system and its impact on the reliability of the BPS. It would seem more appropriate to allow each entity to set their own maximum allowable interval based on studies and historical data of their specific protection system and impact on the reliability of the BPS opposed to a blanket approach that covers all systems regardless of their size or system confirguration.
No
 
 
 
 
Individual
Martin Bauer
US Buereau of Reclamation
No
The alteration of the program to include testing as a component does not add value to system reliability. The existing requirement can only be completed with procedures that some of the elements listed under the program. The proposed program is far too restrictive in the manner in which it requires specific actions and thereby excludes others. The program element for monitoring is listed; however, the monitoring is intended to be used through an electronic subsystem and does not allow for observations by experienced technical staff. Testing is listed; however, the definition is limited to the application of signals and precludes other procedures. Further, the definition of Protection System proposed is a nested definition which tends to expand the number of devices covered (any device that has voltage and current sensing inputs) irrespective of their impact on the BPS.
No
2. The basis for developing the maintenance intervals was adequately explained. It is understood that FERC would like uniform intervals; the intervals do not recognize the tremendous variation in installation and equipment and possibly manufacturer recommendation. Point in fact is the interval for listed for electromechanical relays. Some of these relays must be calibrated every year or three years on the outside. Relays that have a history of stable performance based on consistently good test results. The intervals for battery maintenance are not reasonable. The capacity testing at 3 years is higher than the 5 year which battery manufactures require.
No
The definition of Protection System components does not add clarity. The standard proposes including stations service transformers for generation facilities, however, the protection system definition does not include those elements. The inclusion of station service transformers would only be appropriate if the protection associated with the transformer results in the tripping of a transmission element.
No
The condition based monitoring only provides for a very narrow process and excludes sound judgment in determining maintenance intervals. As long as the registered entity establishes parameters by which variation in the prescribed maintenance intervals are determined, justified variation should be allowed.
No
The parameters established can only be implemented with documentation that defined in the document but is not readily available.
No
6. The document will require revisions. Performance based maintenance is establishing a strategy to achieve a desired performance. The document limits strategy to statistical analysis of failure rates. The document assumes a modern protection system with a high level of monitoring. Facilities which barely qualify would not have high end monitoring installed. The document also refers to “exercising a circuit breaker through t relay tripping circuits using remote control capabilities via data communication.” This repeated several times throughout the document as a means of increasing the TBM. This function, if indeed used, would require maintenance. This function is very dangerous and could introduce a cyber vulnerability.
No
 
 
 
The significance of this issue is not relfected in the period of time needed to review the documents. The supplement has many good ideas; however, the concept is going further than needed for establishing consistent maintenance intervals.