NL-11-2032, D. R. Madison Ltr. Edwin I. Hatch, Appeal to the Executive Director of Operations: Backfit and Applicability of Compliance Backfit Exception: Difference between revisions

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{{#Wiki_filter:Bvnrii& R. Madisop Vir"n Switheirn Nuclearr o p w-alinrg Co nipialiy, I11U POcw. -;2rqj 31;13 Te: ý 1 2.57 ,Th-.q7 C-tt5 EDO DEDMRT DEDR .DEDCM f2-i AO SOUTHERN A.COMPANY October 28, 2011 Docket Nos.: 50-321 50-366 NL-1 1-2032 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant Appeal to the Executive Director of Operations:
{{#Wiki_filter:Bvnrii& R.Madisop       Switheirn Nuclearr Vir"n                 opw-alinrg Co nipialiy, I11U C-tt5  EDO DEDMRT POcw. -Ž;2rqj 31;13                               DEDR    *f  .
Backfit and Aoolicabilitv of "Comoliance Backfit" Exceotion  
Te: ý 12.57 ,Th-.q7 DEDCM   f2-i AO October 28, 2011                                                        SOUTHERN A.
COMPANY Docket Nos.: 50-321                                                     NL-1 1-2032 50-366 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant Appeal to the Executive Director of Operations:
Backfit and Aoolicabilitv of "Comoliance Backfit" Exceotion


==Dear Mr. R. William Borchardt,==
==Dear Mr. R. William Borchardt,==
Southern Nuclear Operating Company (SNC) appeals to the Nuclear Regulatory Commission (NRC) Executive Director of Operations (EDO) the September 29, 2011, determination by the NRC staff that a backfit is necessary at Edwin I.Hatch Nuclear Plant (HNP) awr 4 ilso the staff's application of the "compliance backfit" exception to avoid the requirement for performance of a cost-justified backfit analysis.
 
This letter constitutes SNC's response.
Southern Nuclear Operating Company (SNC) appeals to the Nuclear Regulatory Commission (NRC) Executive Director of Operations (EDO) the September 29, 2011, determination by the NRC staff that a backfit is necessary at Edwin I.
to the September 29, 2011 NRC letter. Notwithstanding this appeal, as a matter of policy, SNC is committed to resolving the issue technically.
Hatch Nuclear Plant (HNP) awr4 ilso the staff's application of the "compliance backfit" exception to avoid the requirement for performance of a cost-justified backfit analysis. This letter constitutes SNC's response. to the September 29, 2011 NRC letter. Notwithstanding this appeal, as a matter of policy, SNC is committed to resolving the issue technically.
Key points pertinent to this issue include: 1. In a February 23,1 995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1 E (safety-related) electrical equipment in the event of degraded voltage conditions.
Key points pertinent to this issue include:
It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable.
: 1. In a February 23,1 995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1E (safety-related) electrical equipment in the event of degraded voltage conditions. It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable. In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995. SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.
In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995. SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.2. On May 25, 2011, the NRC staff issued a letter to SNC providing Inspection Report 05000321 and 366/2011009, regarding the Component Design Bases Inspection (CDBI) performed at HNP in July 2009. That letter concluded that the measures in effect at HNP to demonstrate compliance with the applicable provisions of 10 CFR 50.55a(h)(2) and 10 Tpamp 1"10-1 &IG _(!) n I LiiYX61 U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 2 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-1 7) are not acceptable.
: 2. On May 25, 2011, the NRC staff issued a letter to SNC providing Inspection Report 05000321 and 366/2011009, regarding the Component Design Bases Inspection (CDBI) performed at HNP in July 2009. That letter concluded that the measures in effect at HNP to demonstrate compliance with the applicable provisions of 10 CFR 50.55a(h)(2) and 10 Tpamp 1"10-1 &IG_(!) n I                                                                                   LiiYX61
 
U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 2 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-1 7) are not acceptable.
: 3. A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance.
: 3. A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance.
: 4. The NRC staff recognized that this changed position constituted a backfit.However, the staff also maintained that it does not need to perform a cost-justified substantial safety backfit analysis, as is required by 10 CFR 50.109(a)(3).
: 4. The NRC staff recognized that this changed position constituted a backfit.
Instead, the staff stated that its change in position falls within the "compliance exception" to the staff's backfit analysis obligation which is provided by 10 CFR 50.109(a)(4)(i).
However, the staff also maintained that it does not need to perform a cost-justified substantial safety backfit analysis, as is required by 10 CFR 50.109(a)(3). Instead, the staff stated that its change in position falls within the "compliance exception" to the staff's backfit analysis obligation which is provided by 10 CFR 50.109(a)(4)(i). In a letter dated June 17, 2011, SNC disagreed with the staff's conclusion in the May 25, 2011 letter that a backfit is necessary and that the compliance exception would properly apply to such a backfit and stated the rationale for appealing this decision.
In a letter dated June 17, 2011, SNC disagreed with the staff's conclusion in the May 25, 2011 letter that a backfit is necessary and that the compliance exception would properly apply to such a backfit and stated the rationale for appealing this decision.5. The NRC responded to the SNC appeal by letter dated September 29, 2011, re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate.
: 5. The NRC responded to the SNC appeal by letter dated September 29, 2011, re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate. The stated NRC position was that while SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this license amendment was erroneous and has led SNC to be in violation of GDC-1 7 and 10 CFR 50.55a(h)(2). Because of having taken the position that former NRC approval of the license amendment was erroneous, NRC is exercising enforcement discretion for a duration to be determined after review of SNC's proposed corrective actions and schedule for compliance, to be submitted by SNC within 30 days of the NRC's September 29, 2011 letter.
The stated NRC position was that while SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this license amendment was erroneous and has led SNC to be in violation of GDC-1 7 and 10 CFR 50.55a(h)(2).
: 6. There was no error or mistake made by the staff in approving the 1995 license amendment which established the existing HNP degraded voltage automatic protection scheme. The correspondence preceding the approval shows that the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed, understood, and acknowledged by the staff. No factual errors or omissions are at issue.
Because of having taken the position that former NRC approval of the license amendment was erroneous, NRC is exercising enforcement discretion for a duration to be determined after review of SNC's proposed corrective actions and schedule for compliance, to be submitted by SNC within 30 days of the NRC's September 29, 2011 letter.6. There was no error or mistake made by the staff in approving the 1995 license amendment which established the existing HNP degraded voltage automatic protection scheme. The correspondence preceding the approval shows that the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed, understood, and acknowledged by the staff. No factual errors or omissions are at issue.There were numerous letters and meetings between 1992 and 1995, with the issuance of the final SER in 1995 demonstrating that the NRC approved this change only after careful review.7. The NRC letter of September 29, 2011 misreads IEEE Std. 279-1971,"Criteria for Protection Systems for Nuclear Power Generating Stations," to conclude that the standard does not permit manual action as part of the U. S. Nuclear Regulatory Commission NL- 11-2032 Page 3 protection system, when in fact IEEE Std. 279-1971 contains no such prohibition.
There were numerous letters and meetings between 1992 and 1995, with the issuance of the final SER in 1995 demonstrating that the NRC approved this change only after careful review.
: 8. The staff characterizes the existing HNP degraded voltage protection scheme as reliant solely on manual action. In fact, HNP has a fully automatic degraded voltage protection scheme. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition.
: 7. The NRC letter of September 29, 2011 misreads IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations,"
In fact, the final 1995 SER credited routine manual control action as an integral element of the automatic degraded voltage protection scheme.9. The NRC letter of September 29, 2011 cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate.
to conclude that the standard does not permit manual action as part of the
Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.Enclosure 1 of this letter provides additional discussion of the SNC appeal of the staff's backfit and compliance backfit determinations, with cited supporting documents provided in Enclosure
 
: 3. The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enclosure 2.The NRC staff's May 25 and September 29, 2011, letters, if unaddressed by the EDO, will necessitate a license amendment related to HNP trip setpoints, anticipatory alarms and related requirements.
U. S. Nuclear Regulatory Commission NL- 11-2032 Page 3 protection system, when in fact IEEE Std. 279-1971 contains no such prohibition.
To the extent that the current staff position may require a modification to the HNP license, Southern Nuclear preserves its rights to a formal hearing under Section 189(a)(1) of the.Atomic Energy Act, as amended, 42 U.S.C. § 2239(a)(1).
: 8. The staff characterizes the existing HNP degraded voltage protection scheme as reliant solely on manual action. In fact, HNP has a fully automatic degraded voltage protection scheme. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition. In fact, the final 1995 SER credited routine manual control action as an integral element of the automatic degraded voltage protection scheme.
Southern Nuclear also requests the EDO to observe that development of the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior, 1991 enforcement action. As a matter of established Enforcement Policy, the staff should not reopen that closed action absent "special circumstances" (NRC Enforcement Policy, Sec. 2.3.8). Such special circumstances do not exist here, in that the staff had extensive and detailed information at the time it made its enforcement decision.
: 9. The NRC letter of September 29, 2011 cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate. Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.
Based on this Policy, the EDO should find that the enforcement resolution closes the matter from a backfit.As previously stated in SNC's letter of June 17, 2011, SNC is working to develop a cost-effective resolution to the underlying technical issue, which concerns the margin -under worst-case circumstances and extremely degraded conditions  
Enclosure 1 of this letter provides additional discussion of the SNC appeal of the staff's backfit and compliance backfit determinations, with cited supporting documents provided in Enclosure 3. The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enclosure 2.
-
The NRC staff's May 25 and September 29, 2011, letters, if unaddressed by the EDO, will necessitate a license amendment related to HNP trip setpoints, anticipatory alarms and related requirements. To the extent that the current staff position may require a modification to the HNP license, Southern Nuclear preserves its rights to a formal hearing under Section 189(a)(1) of the.Atomic Energy Act, as amended, 42 U.S.C. § 2239(a)(1).
U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 4 between the minimum expected voltage on the safety-related,4160 V buses at HNP and the minimum voltage required to protect the safety-related equipment on these buses. To this end, SNC is evaluating options to increase this margin and by December 31, 2011 will provide a follow-up letter outlining the proposed technical solution with an implementation schedule.This letter contains no formal NRC commitments.
Southern Nuclear also requests the EDO to observe that development of the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior, 1991 enforcement action. As a matter of established Enforcement Policy, the staff should not reopen that closed action absent "special circumstances" (NRC Enforcement Policy, Sec. 2.3.8). Such special circumstances do not exist here, in that the staff had extensive and detailed information at the time it made its enforcement decision. Based on this Policy, the EDO should find that the enforcement resolution closes the matter from a backfit.
If you have any questions, please contact Mark Ajluni at (205) 992-7673.Respectfully submitted, D. R. Madison Vice President  
As previously stated in SNC's letter of June 17, 2011, SNC is working to develop a cost-effective resolution to the underlying technical issue, which concerns the margin - under worst-case circumstances and extremely degraded conditions -
-Hatch DRM/DWD/lac Enclosure 1: Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception Enclosure 2: Loss of Power Instrumentation Surveillance Requirements Enclosure 3: Appeal to the EDO: Reference Documents cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, President and CEO Mr. D. G. Bost, Chief Nuclear Officer Mr. J. L. Pemberton, Senior VP & General Counsel Ms. P. M. Marino, Vice President  
 
-Engineering Mr. M. J. Ajluni, Nuclear Licensing Director RTYPE: CHA02.004 U. S. Nuclear Requlatory Commission Mr. J. T. Munday, Director -Division of Reactor Safety Mr. V. M. McCree, Regional Administrator Mr. W. C. Gleaves, NRR Project Manager Mr. E. D. Morris, Senior Resident Inspector  
U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 4 between the minimum expected voltage on the safety-related,4160 V buses at HNP and the minimum voltage required to protect the safety-related equipment on these buses. To this end, SNC is evaluating options to increase this margin and by December 31, 2011 will provide a follow-up letter outlining the proposed technical solution with an implementation schedule.
-Hatch Edwin I. Hatch Nuclear Plant Enclosure 1 Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception Introduction Southern Nuclear Operating Company (SNC) is the licensed operator of the Edwin I. Hatch Nuclear Plant (HNP). In a letter dated May 25, 2011, the Nuclear Regulatory Commission (NRC) staff advised SNC that the degraded voltage protection scheme at HNP did not comply with 10 CFR 50.55a(h)(2) and 10 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-17).
This letter contains no formal NRC commitments.
The May 25 letter acknowledged that the NRC staff's position -that "administrative controls to assure adequate voltage to safety-related equipment during certain design basis events" was not an acceptable method for compliance with 10 CFR 50.55a(h)(2) and GDC 17 -was a change in a NRC staff position and therefore constituted a backfit as defined in 10 CFR 50.109. The May 25 letter maintained, however, that no cost-justified substantial safety backfit analysis, as required by 10 CFR 50.109(a)(3), is required because the change falls within the "compliance backfit" exception to the staff's backfit analysis obligation in 10 CFR 50.109(a)(4)(i).
Ifyou have any questions, please contact Mark Ajluni at (205) 992-7673.
By letter dated June 17, 2011, SNC appealed to the NRC staff the staff's determination that the backfit qualified for the 50.109(a)(4)(i) "compliance backfit" exception.
Respectfully submitted, D. R. Madison Vice President - Hatch DRM/DWD/lac : Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception : Loss of Power Instrumentation Surveillance Requirements : Appeal to the EDO: Reference Documents cc:   Southern Nuclear Operating Company Mr. S. E. Kuczynski, President and CEO Mr. D. G. Bost, Chief Nuclear Officer Mr. J. L. Pemberton, Senior VP & General Counsel Ms. P. M. Marino, Vice President - Engineering Mr. M. J. Ajluni, Nuclear Licensing Director RTYPE: CHA02.004 U. S. Nuclear Requlatory Commission Mr. J. T. Munday, Director - Division of Reactor Safety Mr. V. M. McCree, Regional Administrator Mr. W. C. Gleaves, NRR Project Manager Mr. E. D. Morris, Senior Resident Inspector - Hatch
In a letter dated September 29, 2011, the NRC staff responded to the SNC appeal by re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate.
 
SNC hereby appeals this determination to the NRC Executive Director of Operations (EDO), pursuant to the NRC Manual, Chapter 0514 (Management Directive 8.4).SNC appeals the NRC staff's decision to issue a backfit under the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) related to the degraded voltage protection scheme at Edwin I. Hatch Nuclear Plant (HNP). SNC requests that the EDO reverse the NRC staff's determination that: (1) the HNP degraded voltage protection scheme does not comply with the applicable regulations and (2) the acknowledged backf it constitutes a "compliance backf it" under 10 CFR 50.109(a)(4).
Edwin I. Hatch Nuclear Plant Enclosure 1 Appeal to the EDO:
SNC requests the EDO find that HNP is currently in compliance with 10 CFR 50.55a(h)(2) and GDC 17 and that the NRC staff's change in position regarding the requirements of those regulations does not satisfy the"compliance backfit" exception to 10 CFR 50.109(a)(4)(i).
Backfit and Applicability of "Compliance Backfit" Exception
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception Introduction Southern Nuclear Operating Company (SNC) is the licensed operator of the Edwin I. Hatch Nuclear Plant (HNP). In a letter dated May 25, 2011, the Nuclear Regulatory Commission (NRC) staff advised SNC that the degraded voltage protection scheme at HNP did not comply with 10 CFR 50.55a(h)(2) and 10 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-17). The May 25 letter acknowledged that the NRC staff's position - that "administrative controls to assure adequate voltage to safety-related equipment during certain design basis events" was not an acceptable method for compliance with 10 CFR 50.55a(h)(2) and GDC 17 - was a change in a NRC staff position and therefore constituted a backfit as defined in 10 CFR 50.109. The May 25 letter maintained, however, that no cost-justified substantial safety backfit analysis, as required by 10 CFR 50.109(a)(3), is required because the change falls within the "compliance backfit" exception to the staff's backfit analysis obligation in 10 CFR 50.109(a)(4)(i).
By letter dated June 17, 2011, SNC appealed to the NRC staff the staff's determination that the backfit qualified for the 50.109(a)(4)(i) "compliance backfit" exception. In a letter dated September 29, 2011, the NRC staff responded to the SNC appeal by re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate. SNC hereby appeals this determination to the NRC Executive Director of Operations (EDO),
pursuant to the NRC Manual, Chapter 0514 (Management Directive 8.4).
SNC appeals the NRC staff's decision to issue a backfit under the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) related to the degraded voltage protection scheme at Edwin I. Hatch Nuclear Plant (HNP). SNC requests that the EDO reverse the NRC staff's determination that: (1) the HNP degraded voltage protection scheme does not comply with the applicable regulations and (2) the acknowledged backf it constitutes a "compliance backf it" under 10 CFR 50.109(a)(4). SNC requests the EDO find that HNP is currently in compliance with 10 CFR 50.55a(h)(2) and GDC 17 and that the NRC staff's change in position regarding the requirements of those regulations does not satisfy the "compliance backfit" exception to 10 CFR 50.109(a)(4)(i).


===Background===
===Background===
In a February 23, 1995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1 E (safety-related) electrical equipment in the event of degraded voltage conditions.
In a February 23, 1995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1E (safety-related) electrical equipment in the event of degraded voltage conditions. It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable. In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995.
It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable.
SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.
In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995.SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.Enclosure 1 Page 1 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception The SER approving the deviation and license amendment also recognized that the HNP design configuration satisfied the requirements of GDC-17: 'With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10 CFR Part 50, Appendix A." As a result of the Component Design Bases Inspection (CDBI) at HNP in July 2009, the NRC staff asserted that SNC was not in compliance with the degraded voltage protection requirements of 10 CFR 50.55a(h)(2) and General Design Criterion 17 (GDC-17).
Enclosure 1 Page 1 of 12
In its May 25, 2011 letter, the NRC staff stated that HNP was not in compliance with the degraded voltage protection requirements of GDC 17 and 10 CFR 50.55a(h)(2) and directed that HNP implement a backfit excluding reliance on manual action to maintain grid voltages.
 
The NRC staff asserts that, although SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this 1995 license amendment was erroneous and, consequently, that SNC is in violation of GDC-17 and 10 CFR 50.55a(h)(2).
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception The SER approving the deviation and license amendment also recognized that the HNP design configuration satisfied the requirements of GDC-17:
Accordingly, the NRC staff asserts that the backfit qualifies for the "compliance backfit" exception codified at 10 CFR 50.109(a)(4)(i).
        'With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10 CFR Part 50, Appendix A."
The NRC's regulations, for purposes relevant here, at 10 CFR 50.109(a)(1) define a backfit as: "...the modification of ... design of a facility...or imposition of a regulatory staff position interpreting the Commission's regulations that is either new or different from a previously applicable staff position." The NRC staff acknowledges that its current position is a change from the NRC position reflected in the 1995 SER approving the deviation from the 1977 guidance and "constitutes backfitting." More specifically, in the Evaluation attached to the September 29, 2011 letter denying SNC's initial appeal, the NRC staff recognizes at page 3 that "a deviation from the guidance on degraded voltage protection provided in the NRC letter dated June 2, 1977 was accepted by the NRC in a SER dated February 23, 1995." While it is clear that the NRC staff's letter of May 25, 2011 seeks to impose a backfit, SNC believes that the NRC staff's reliance on the compliance backfit provision of 10 CFR 50.109(a)(4)(i) is misplaced.
As a result of the Component Design Bases Inspection (CDBI) at HNP in July 2009, the NRC staff asserted that SNC was not in compliance with the degraded voltage protection requirements of 10 CFR 50.55a(h)(2) and General Design Criterion 17 (GDC-17). In its May 25, 2011 letter, the NRC staff stated that HNP was not in compliance with the degraded voltage protection requirements of GDC 17 and 10 CFR 50.55a(h)(2) and directed that HNP implement a backfit excluding reliance on manual action to maintain grid voltages. The NRC staff asserts that, although SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this 1995 license amendment was erroneous and, consequently, that SNC is in violation of GDC-17 and 10 CFR 50.55a(h)(2). Accordingly, the NRC staff asserts that the backfit qualifies for the "compliance backfit" exception codified at 10 CFR 50.109(a)(4)(i).
SNC's appeal of the NRC's decision to issue a backfit and to apply the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) is based on the following:
The NRC's regulations, for purposes relevant here, at 10 CFR 50.109(a)(1) define a backfit as:
(1) the 1995 approval of HNP's degraded voltage protection scheme was not based on a mistake of fact or error;(2) the approved configuration is adequate relative to risk and complies with applicable regulations; Enclosure 1 Page 2 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception (3) the "compliance backfif' exception is not applicable to a change in NRC staff position regarding compliance with a regulation; and (4) imposition of the backfit as a compliance backfit would be contrary to NRC's principles of good regulation in that it would not promote a stable regulatory environment.
          "...the modification of ... design of a facility...or imposition of a regulatory staff position interpreting the Commission's regulations that is either new or different from a previously applicable staff position."
I. The approval of the current HNP degraded voltage configuration in 1995 was not based on a mistake of fact or error.A. The NRC staff in 1995 was cognizant of and understood the approved deviation from the 1977 guidance.Contrary to the NRC staff's assertions underlying the current backfit, the 1995 approval of the configuration of the HNP degraded voltage protection scheme by the staff was not based on an error or mistake of fact. SNC submits that the historic correspondence between SNC and the NRC staff demonstrates that the NRC fully recognized in 1995 that its approval of the HNP system was a deviation from the 1977 NRC staff guidance.1 In effect, the NRC staff's analysis in 1995 was similar to the cost-justified substantial safety backfit analysis that SNC contends should be performed now as a condition to the imposition of the current backfit.The NRC staff acknowledges that correspondence between SNC and the NRC and other documentation, including two (2) SERs, demonstrates that the NRC staff formally reviewed and approved the degraded grid voltage Loss of Offsite Power (LOP) and Loss of Coolant Accident (LOCA) scenarios for HNP. Those SERs examined the sufficiency of voltage for concurrent LOP and LOCA, the likelihood of such an event, and the positive safety consequences associated with additional degraded voltage alarms, operator monitoring and potential action, and the specific setpoints for degraded voltage relays that initiate automatic separation of the plant from the system. However, the NRC staff asserts that the 1995 approval was in "error" or a "mistake." The basis for that assertion appears twofold: 1) the NRC staff in 1995 "did not explain why" the deviation from NRC's 1977 guidance was approved and, therefore, was apparently without basis (e.g.lack of information or based on inaccurate information), or 2) the 1995 conclusion to approve the license amendment including the deviation was an analytical error.Contrary to the NRC staff's current rationale for asserting that NRC's 1995 SER was mistaken or otherwise in error, the contemporaneous documentation from the early 1990s demonstrates that the NRC staff at that time was fully aware and 1 The 1995 staff understood that the 1977 guidance was a position, not a regulation.
The NRC staff acknowledges that its current position is a change from the NRC position reflected in the 1995 SER approving the deviation from the 1977 guidance and "constitutes backfitting." More specifically, in the Evaluation attached to the September 29, 2011 letter denying SNC's initial appeal, the NRC staff recognizes at page 3 that "a deviation from the guidance on degraded voltage protection provided in the NRC letter dated June 2, 1977 was accepted by the NRC in a SER dated February 23, 1995."
The 1995 staff SER expressly referred to the June 2, 1977 letter as"current NRC staff guidance" and "Staff Positions" regarding onsite emergency power systems.Enclosure 1 Page 3 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception cognizant of the issue at hand and of the resolution that it was approving.
While it is clear that the NRC staff's letter of May 25, 2011 seeks to impose a backfit, SNC believes that the NRC staff's reliance on the compliance backfit provision of 10 CFR 50.109(a)(4)(i) is misplaced. SNC's appeal of the NRC's decision to issue a backfit and to apply the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) is based on the following:
The documentation underlying the NRC's approval of the 1995 license amendment establishes that the deviation from the 1977 staff guidance was approved only after the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed.
(1)         the 1995 approval of HNP's degraded voltage protection scheme was not based on a mistake of fact or error; (2)         the approved configuration is adequate relative to risk and complies with applicable regulations; Enclosure 1 Page 2 of 12
The approval was risk-informed and appropriately considered the relative alternatives:
 
: 1. In 1982, EG&G, an NRC contractor, prepared a review of the degraded grid protection for Class 1E power systems at HNP (Enc. 3, Item 1). The contractor identified the design basis criteria, including GDC-17, IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations" and the NRC "Staff positions as detained in a letter sent to the licensee, dated June 3, 1977". The licensee provided the contractor with proposed changes to the Technical Specifications, allowable limits for setpoint and time delay, and LCOs applicable to the second level voltage monitors.
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception (3)       the "compliance backfif' exception is not applicable to a change in NRC staff position regarding compliance with a regulation; and (4)       imposition of the backfit as a compliance backfit would be contrary to NRC's principles of good regulation in that it would not promote a stable regulatory environment.
Here, then, was manual action as a component of undervoltage protection, with relays set to operate and disconnect at 2912 V (70%).2. In 1991, during an Electrical Distribution System Functional Inspection, the NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnection from offsite power supply. Thereafter, the staff issued an inspection report on August 22, 1991, and a Notice of Violation (NOV) on October 7, 1991. The violation was contested by the licensee by letter dated November 6, 1991.The licensee maintained that the existing degraded grid protection scheme complied with the staff's positions in the June 2, 1977 letter.Enclosure 3, Items 2, 3 & 4 are the Inspection Report, the NOV and the licensee's response, respectively.
I. The approval of the current HNP degraded voltage configuration in 1995 was not based on a mistake of fact or error.
: 3. A meeting was held between the licensee and the staff on November 16, 1992 to address the matter; seven full-time and two part-time NRC representatives attended (Enc. 3, Item 5 is handouts from the meeting).Two licensee letters, dated November 22, 1993 and July 1, 1994 (Enc. 3, Items 6 & 7) were followed by another meeting with the staff on December 7, 1994 (January 10, 1995 meeting summary at Enc. 3, Item 8). The NRC responded with the SER on February 23, 1995 (Enc. 3, Item 9).In summary, SNC and the NRC staff disagreed on a NOV, found common ground for a resolution that complied with GDC-17, the NRC staff evaluated that resolution and imposed additional conditions to which SNC agreed. Thus, there was no mistake or error in the NRC's approval of the license amendment that included a deviation from the June, 1977 guidance.B. The NRC staff understood that the approved deviation included licensee commitments that added design features for enhanced safety. These Enclosure 1 Page 4 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception enhancements guard against spurious disconnections from the preferred backup power source, when available.
A. The NRC staff in 1995 was cognizant of and understood the approved deviation from the 1977 guidance.
The NRC's 1995 SER for the degraded grid voltage protection scheme includes the following, which demonstrates the staff's imposition of requirements for design features to the system that enhance safety. For over 16 years, HNP has implemented those features, as part of the approved design. The SER states: "The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:
Contrary to the NRC staff's assertions underlying the current backfit, the 1995 approval of the configuration of the HNP degraded voltage protection scheme by the staff was not based on an error or mistake of fact. SNC submits that the historic correspondence between SNC and the NRC staff demonstrates that the NRC fully recognized in 1995 that its approval of the HNP system was a deviation from the 1977 NRC staff guidance.1 In effect, the NRC staff's analysis in 1995 was similar to the cost-justified substantial safety backfit analysis that SNC contends should be performed now as a condition to the imposition of the current backfit.
: 1. The degraded voltage alarm relays should be included in the plant Technical Specification along with the degraded voltage relays that initiate automatic actions.2. The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.
The NRC staff acknowledges that correspondence between SNC and the NRC and other documentation, including two (2) SERs, demonstrates that the NRC staff formally reviewed and approved the degraded grid voltage Loss of Offsite Power (LOP) and Loss of Coolant Accident (LOCA) scenarios for HNP. Those SERs examined the sufficiency of voltage for concurrent LOP and LOCA, the likelihood of such an event, and the positive safety consequences associated with additional degraded voltage alarms, operator monitoring and potential action, and the specific setpoints for degraded voltage relays that initiate automatic separation of the plant from the system. However, the NRC staff asserts that the 1995 approval was in "error" or a "mistake." The basis for that assertion appears twofold: 1) the NRC staff in 1995 "did not explain why" the deviation from NRC's 1977 guidance was approved and, therefore, was apparently without basis (e.g.
lack of information or based on inaccurate information), or 2) the 1995 conclusion to approve the license amendment including the deviation was an analytical error.
Contrary to the NRC staff's current rationale for asserting that NRC's 1995 SER was mistaken or otherwise in error, the contemporaneous documentation from the early 1990s demonstrates that the NRC staff at that time was fully aware and 1 The 1995 staff understood that the 1977 guidance was a position, not a regulation. The 1995 staff SER expressly referred to the June 2, 1977 letter as "current NRC staff guidance" and "Staff Positions" regarding onsite emergency power systems.
Enclosure 1 Page 3 of 12
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception cognizant of the issue at hand and of the resolution that it was approving. The documentation underlying the NRC's approval of the 1995 license amendment establishes that the deviation from the 1977 staff guidance was approved only after the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed. The approval was risk-informed and appropriately considered the relative alternatives:
: 1. In 1982, EG&G, an NRC contractor, prepared a review of the degraded grid protection for Class 1E power systems at HNP (Enc. 3, Item 1). The contractor identified the design basis criteria, including GDC-17, IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations" and the NRC "Staff positions as detained in a letter sent to the licensee, dated June 3, 1977". The licensee provided the contractor with proposed changes to the Technical Specifications, allowable limits for setpoint and time delay, and LCOs applicable to the second level voltage monitors. Here, then, was manual action as a component of undervoltage protection, with relays set to operate and disconnect at 2912 V (70%).
: 2. In 1991, during an Electrical Distribution System Functional Inspection, the NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnection from offsite power supply. Thereafter, the staff issued an inspection report on August 22, 1991, and a Notice of Violation (NOV) on October 7, 1991. The violation was contested by the licensee by letter dated November 6, 1991.
The licensee maintained that the existing degraded grid protection scheme complied with the staff's positions in the June 2, 1977 letter.
Enclosure 3, Items 2, 3 & 4 are the Inspection Report, the NOV and the licensee's response, respectively.
: 3. A meeting was held between the licensee and the staff on November 16, 1992 to address the matter; seven full-time and two part-time NRC representatives attended (Enc. 3, Item 5 is handouts from the meeting).
Two licensee letters, dated November 22, 1993 and July 1, 1994 (Enc. 3, Items 6 & 7) were followed by another meeting with the staff on December 7, 1994 (January 10, 1995 meeting summary at Enc. 3, Item 8). The NRC responded with the SER on February 23, 1995 (Enc. 3, Item 9).
In summary, SNC and the NRC staff disagreed on a NOV, found common ground for a resolution that complied with GDC-17, the NRC staff evaluated that resolution and imposed additional conditions to which SNC agreed. Thus, there was no mistake or error in the NRC's approval of the license amendment that included a deviation from the June, 1977 guidance.
B. The NRC staff understood that the approved deviation included licensee commitments that added design features for enhanced safety. These Enclosure 1 Page 4 of 12
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception enhancements guard against spurious disconnections from the preferred backup power source, when available.
The NRC's 1995 SER for the degraded grid voltage protection scheme includes the following, which demonstrates the staff's imposition of requirements for design features to the system that enhance safety. For over 16 years, HNP has implemented those features, as part of the approved design. The SER states:
        "The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:
: 1. The degraded voltage alarm relays should be included in the plant Technical Specification along with the degraded voltage relays that initiate automatic actions.
: 2. The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.
The licensee has agreed to these added conditions.
The licensee has agreed to these added conditions.
With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10.CFR Part 50, Appendix A." C. The 1995 SER expressly approved reliance on manual actions to respond to a narrow 3% band of degraded grid voltages.
With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10.CFR Part 50, Appendix A."
In addition, the SER acknowledged that certain class 1 E loads at voltage levels of 600 volts and below might not receive sufficient voltage upon automatic disconnection from the grid with the HNP configuration.
C. The 1995 SER expressly approved reliance on manual actions to respond to a narrow 3% band of degraded grid voltages. In addition, the SER acknowledged that certain class 1 E loads at voltage levels of 600 volts and below might not receive sufficient voltage upon automatic disconnection from the grid with the HNP configuration.
A description of the manual actions approved to respond to such degraded voltage conditions is contained in the staff's March 3, 1995 SER for the Improved Technical Specifications (ITS): "...HNP credits manual actions in the range of 78.8% to 92% of 4.16kV.Entry into this range is annunciated.
A description of the manual actions approved to respond to such degraded voltage conditions is contained in the staff's March 3, 1995 SER for the Improved Technical Specifications (ITS):
The range specified for manual action indicates that sufficient power is available to the large ECCS pump motors. However, sufficient voltage for the equipment required for loss-of-coolant accident (LOCA) conditions may not be available at lower voltages.
        "...HNP credits manual actions in the range of 78.8% to 92% of 4.16kV.
The required channels of LOP annunciation instrumentation ensure the initiation of manual actions to protect the ECCS and other assumed systems from degraded voltage without initiating an Enclosure 1 Page 5 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception unnecessary automatic disconnect from the preferred offsite power source. The LOP anticipatory annunciators are designed with a time delay of 65 seconds to reduce the possibility of nuisance annunciators while permitting prompt detection of potential low voltage conditions.
Entry into this range is annunciated. The range specified for manual action indicates that sufficient power is available to the large ECCS pump motors. However, sufficient voltage for the equipment required for loss-of-coolant accident (LOCA) conditions may not be available at lower voltages. The required channels of LOP annunciation instrumentation ensure the initiation of manual actions to protect the ECCS and other assumed systems from degraded voltage without initiating an Enclosure 1 Page 5 of 12
HNP takes credit for the annunciators in restoring acceptable voltage levels.Therefore, improved TS Table 3.3.8.1-1 is being added to the CTS[Current Technical Specification]
 
requirements.
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception unnecessary automatic disconnect from the preferred offsite power source. The LOP anticipatory annunciators are designed with a time delay of 65 seconds to reduce the possibility of nuisance annunciators while permitting prompt detection of potential low voltage conditions. HNP takes credit for the annunciators in restoring acceptable voltage levels.
Additionally, ACTION B, addressing the annunciator function, is being added and the other functions are renumbered and amended to provide for the annunciation.
Therefore, improved TS Table 3.3.8.1-1 is being added to the CTS
SRs [Surveillance Requirements]
[Current Technical Specification] requirements. Additionally, ACTION B, addressing the annunciator function, is being added and the other functions are renumbered and amended to provide for the annunciation.
are also being added for the annunciator bus undervoltage and associated time delay relays." In conclusion, the 1995 staff was informed, knowledgeable and engaged in the approval of the current HNP degraded voltage protection scheme. While the current staff may have a difference in professional opinion about that approval, that opinion is not a sufficient basis for a backfit and for an exception to the requirement for performing a cost-justified safety benefit evaluation.
SRs [Surveillance Requirements] are also being added for the annunciator bus undervoltage and associated time delay relays."
I1. The current HNP degraded voltage configuration is adequate relative to risk and complies with the applicable regulations.
In conclusion, the 1995 staff was informed, knowledgeable and engaged in the approval of the current HNP degraded voltage protection scheme. While the current staff may have a difference in professional opinion about that approval, that opinion is not a sufficient basis for a backfit and for an exception to the requirement for performing a cost-justified safety benefit evaluation.
In the Sept. 29, 2011, NRC Evaluation of Licensee Backfit Appeal, on page 4 the NRC staff maintains that the error in the NRC's 1995 SER was that the 1995 SER: "...was not based on the guiding principle of the NRC position that the sole reliance on manual controls for degraded grid voltage protection may result in the Class 1 E bus voltages being too low for operation of safety-related equipment but high enough to prevent separation of the safety buses for the offsite power supply." (italics supplied)Similar wording is found elsewhere in the Evaluation.
I1.The current HNP degraded voltage configuration is adequate relative to risk and complies with the applicable regulations.
For example, on page 6 the NRC staff states the IEEE Std. 603-1991 requires design basis documentation for justification of "permitting initiation or control subsequent to initiation solely by manual means" and on page 7 the NRC concludes that "...the backfit per the compliance exception..." issued to SNC "...for its reliance solely on manual controls for degraded grid voltage protection was appropriate".
In the Sept. 29, 2011, NRC Evaluation of Licensee Backfit Appeal, on page 4 the NRC staff maintains that the error in the NRC's 1995 SER was that the 1995 SER:
Contrary to this characterization, HNP does not rely solely on manual controls for degraded grid voltage protection.
        "...was not based on the guiding principle of the NRC position that the sole reliance on manual controls for degraded grid voltage protection may result in the Class 1E bus voltages being too low for operation of safety-related equipment but high enough to prevent separation of the safety buses for the offsite power supply." (italics supplied)
The manual actions "credited" to prevent inadequate voltage conditions were limited to manual actions by plant operators in a specific band of degraded voltages followed by automatic actuation at a lower system voltage setpoint: "The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3%band between 91% (3786 volts) and 88.34% (3675 volts) certain class 1 E Enclosure 1 Page 6 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception loads at voltage levels of 600 volts and below may not receive sufficient voltage." -SNC to NRC letter dated November 22, 1993 (Enc. 3, Item 6)"...the degraded grid protection system uses manual action instead of automatic disconnect in the range of the deadband.
Similar wording is found elsewhere in the Evaluation. For example, on page 6 the NRC staff states the IEEE Std. 603-1991 requires design basis documentation for justification of "permitting initiation or control subsequent to initiation solely by manual means" and on page 7 the NRC concludes that "...the backfit per the compliance exception..." issued to SNC "...for its reliance solely on manual controls for degraded grid voltage protection was appropriate".
Accordingly, GPC[the licensee]
Contrary to this characterization, HNP does not rely solely on manual controls for degraded grid voltage protection. The manual actions "credited" to prevent inadequate voltage conditions were limited to manual actions by plant operators in a specific band of degraded voltages followed by automatic actuation at a lower system voltage setpoint:
has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent,[plant] operators will initiate a 'one hour to restore' action statement.
          "The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3%
If voltages are not restored within one hour, a plant shutdown is then initiated." -GPC to NRC letter dated July 1, 1994.(Enc.
band between 91% (3786 volts) and 88.34% (3675 volts) certain class 1E Enclosure 1 Page 6 of 12
3, Item 7)As can be observed in the handouts from the NRC and licensee meeting of November 16, 1992 (Enc. 3, Item 5), and the attachment to the licensee's November 22, 1993 letter (Enc. 3, Item 6) the staff was aware that automatic disconnection from the grid would occur at 88.34% of 4160 volts.2 Neither GDC-17 or 10 CFR 50.55a(h)(2) expressly prohibit manual actions in response to degraded voltage conditions.
 
GDC-1 7 is descriptive of offsite and onsite power supplies and speaks to the importance of minimizing the probability of coincident loss of power supplies -implicitly in order of safety importance  
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception loads at voltage levels of 600 volts and below may not receive sufficient voltage." - SNC to NRC letter dated November 22, 1993 (Enc. 3, Item 6)
-power from the unit, from the grid and from onsite backup power supplies."Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies." The HNP license includes requirements for anticipatory alarms, their setpoints and periodic testing (surveillance), and a limiting condition for operation (LCO).These requirements address the potential for a grid voltage drop to the minimum expected level due to a plant trip, which is the most likely grid event. The express license requirements do not require a backfit. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition.
        "...the degraded grid protection system uses manual action instead of automatic disconnect in the range of the deadband. Accordingly, GPC
This approach has been very successful; a review of system operating records and plant logs dating back to the March 14, 1993 degraded grid event described in the 1995 SER found no instance of the degraded grid alarm having ever annunciated at HNP.GDC-17 states that "an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The 2 Current tap setting is 78.8% of 4160 volts.Enclosure 1 Page 7 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception safety function.. .shall be to provide sufficient capacity and capability.. .as a result of anticipated operational occurrences." HNP's design and operation meets this requirement in that it has the capacity and capability for the anticipated grid conditions, including N-1 contingencies.
[the licensee] has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent,
In addition, the potential for a degraded grid at HNP (although unanticipated) is minimized by the plant and grid operational features described herein, and results in an extremely low probability of occurrence.
[plant] operators will initiate a 'one hour to restore' action statement. If voltages are not restored within one hour, a plant shutdown is then initiated." - GPC to NRC letter dated July 1, 1994.(Enc. 3, Item 7)
A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance.
As can be observed in the handouts from the NRC and licensee meeting of November 16, 1992 (Enc. 3, Item 5), and the attachment to the licensee's November 22, 1993 letter (Enc. 3, Item 6) the staff was aware that     2 automatic disconnection from the grid would occur at 88.34% of 4160 volts.
SNC has determined this value through a best estimate approach with appropriate conservatism.
Neither GDC-17 or 10 CFR 50.55a(h)(2) expressly prohibit manual actions in response to degraded voltage conditions. GDC-1 7 is descriptive of offsite and onsite power supplies and speaks to the importance of minimizing the probability of coincident loss of power supplies - implicitly in order of safety importance -
The September 29, 2011 NRC Evaluation of Licensee Backf it Appeal cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate.
power from the unit, from the grid and from onsite backup power supplies.
It should be noted (as the NRC concluded in its own documented evaluations) that neither of these two events was due to grid voltage conditions below expected values. The plant voltage issues were due instead to inadequate plant design for the anticipated grid and plant operational conditions.
        "Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies."
Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.10 CFR 50.55a(h)(2), specifies the codes and standards applicable to nuclear power plant protection systems, and incorporates by reference IEEE Standards.
The HNP license includes requirements for anticipatory alarms, their setpoints and periodic testing (surveillance), and a limiting condition for operation (LCO).
For HNP, IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," is the requirement applicable to the degraded grid protection system. To support its current "compliance backfit" argument, the NRC staff relies on its interpretation of the "intent" of IEEE Std. 279-1971, rather than applying language actually found in the standard.
These requirements address the potential for a grid voltage drop to the minimum expected level due to a plant trip, which is the most likely grid event. The express license requirements do not require a backfit. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition. This approach has been very successful; a review of system operating records and plant logs dating back to the March 14, 1993 degraded grid event described in the 1995 SER found no instance of the degraded grid alarm having ever annunciated at HNP.
Notwithstanding its acknowledgement on page 6 of the Evaluation that IEEE Std. 279-1971"acknowledges the use of manual action and initiation of protection systems by manual actions," the staff adds its own gloss to the language of the standard in order to narrow its scope by stating that "manual action as discussed in Section 4.17 is intended to be 'in addition to,' as a backup, and not 'in lieu of' the automatic initiation requirement of Section 4.1." Again, for the HNP degraded grid protective scheme, manual action by operators is taken before the plant conditions for automatic actuation are reached.Specifically, the November 22, 1993 GPC letter (Enc. 3, Item 6), the July 1, 1994 GPC letter to the NRC (Enc. 3, Item 7), the January 10, 1995 NRC meeting notes (Enc. 3, Item 8), and February 23, 1995 NRC SER (Enc. 3, Item 9) address in detail the plant's response to degraded grid conditions, the setpoints for automatic disconnection, and anticipatory alarms and potential manual actions at Enclosure 1 Page 8 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception below 92%. An automatic degraded grid trip for voltages below 88.34% (currently 78.8%) of bus voltage was approved by the NRC staff for the automatic disconnect, provided that the anticipatory alarm relays and degraded voltage relays came into the Technical Specifications. (The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enc. 2.)Manual action instead of automatic trip is applicable, then, only to a narrow band of voltages above the automatic trip level. Once the trip setpoint is reached, the actuation of the protection system goes to completion without manual intervention, in accordance with IEEE Std. 279-1971 at §4.16 on pg. 10. No regulation, order or commitment precludes anticipatory manual action for degraded grid voltages as a component of a plant's degraded grid configuration.
GDC-17 states that "an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The 2 Current tap setting is 78.8% of 4160 volts.
Ill. The "compliance backfit exception" is not applicable to the change in NRC staff positions in this matter."The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact." See 50 Fed. Reg.38097, 38103 (Sept. 20, 1985).Whether the NRC staff's invocation of the compliance backfit exception in 10 CFR 50.109(a)(4)(i) supports the backfit discussed in its May 25, 2011 letter depends on whether that exception may be used to avoid a cost-justified substantial safety backfit analysis when the NRC staff changes its position regarding what is necessary to comply with a regulatory requirement, as opposed to whether a facility or license is in compliance with a clearly stated regulatory requirement.
Enclosure 1 Page 7 of 12
As stated in 10 CFR 50.109(a)(4)(i), the exception applies where "a modification is necessary to bring a facility into compliance with a license or the rules or orders of the Commission, or into conformance with written commitments by the licensee." The backfit imposed by the NRC staff's May 25, 2011 letter incorrectly relies on the "compliance backfit exception" to avoid the obligation of the NRC staff to perform a cost-justified substantial safety backfit analysis.The NRC staff's rationale for invoking the compliance backfit exception is that it disagrees with the NRC's 1995 determination that the HNP degraded grid protection system satisfies both 10 CFR 50.55a(h)(2) and GDC-17. As stated on page 3 of the Sept. 29, 2011 NRC Evaluation of Licensee Backf it Appeal: "...the backfitting action is necessary for compliance with GDC-17 and 10 CFR 50.55a(h)(2) and is consistent with applicable guidance and practices in effect at the time the NRC staff erroneously approved the use of manual actions for controlling voltages at HNP." This statement is instructive.
 
First, the NRC staff says that the backfitting action is necessary for compliance with two specific regulations.
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception safety function.. .shall be to provide sufficient capacity and capability.. .as a result of anticipated operational occurrences." HNP's design and operation meets this requirement in that it has the capacity and capability for the anticipated grid conditions, including N-1 contingencies. In addition, the potential for a degraded grid at HNP (although unanticipated) is minimized by the plant and grid operational features described herein, and results in an extremely low probability of occurrence.
As set forth above, however, the NRC in 1995 expressly addressed the compliance of the HNP Enclosure 1 Page 9 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception system under the same regulations and came to a different conclusion than the NRC staff does today. Because the NRC staff's position in 2011 is not based on the express language of either regulation but on the "intent" of the regulations, the difference of opinion is clearly a change in NRC staff position, not a mistake or error by the NRC in 1995.The NRC staff's invocation of the compliance backfit exception under these circumstances would improperly enlarge the scope of the exception from"omissions or mistakes of fact" to encompass alleged "approval errors" for deviations to staff positions which were based on accurate and complete facts.Application of the compliance backfit exception in this way would be inconsistent with the clear language and intent of the backfit rule. 'The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact. It should be noted that new or modified interpretations of what constitutes compliance would not fall within the exception and would require a backfit analysis and application of the standard." See 50 Fed. Reg. 38097, 38103 (Sept.20, 1985). See also NUREG 1409 § 3.1 at pg. 12 (which cites this statement from the Federal Register notice).Second, the NRC staff says that backfitting action is "consistent with" historic guidance.
A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance. SNC has determined this value through a best estimate approach with appropriate conservatism.
NRC guidance documents are not regulations.
The September 29, 2011 NRC Evaluation of Licensee Backf it Appeal cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate. It should be noted (as the NRC concluded in its own documented evaluations) that neither of these two events was due to grid voltage conditions below expected values. The plant voltage issues were due instead to inadequate plant design for the anticipated grid and plant operational conditions. Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.
They have not gone through the Administrative Procedures Act process and the vetting appropriate for rules. For example, Branch Technical Position (BTP) 8-6 (Rev. 3, March, 2007),"Adequacy of Station Electric Distribution Voltages," is found in NUREG 0800, Chapter 8 as part of the Standard Review Plan. The first footnote in BTP 8-6 includes:  
10 CFR 50.55a(h)(2), specifies the codes and standards applicable to nuclear power plant protection systems, and incorporates by reference IEEE Standards.
"...the Standard Review Plan is not a substitute for the NRC's regulations, and compliance with it is not required." Thus, the BTP is not a regulation. "Consistent with" is not equal to "mandated by." Important distinctions apply to "legal requirements", "commitments" and "staff positions" in the context of backfits:* Legal requirements are contained in explicit regulations, orders, and plant licenses (amendments, conditions, technical specifications).
For HNP, IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," is the requirement applicable to the degraded grid protection system. To support its current "compliance backfit" argument, the NRC staff relies on its interpretation of the "intent" of IEEE Std. 279-1971, rather than applying language actually found in the standard. Notwithstanding its acknowledgement on page 6 of the Evaluation that IEEE Std. 279-1971 "acknowledges the use of manual action and initiation of protection systems by manual actions," the staff adds its own gloss to the language of the standard in order to narrow its scope by stating that "manual action as discussed in Section 4.17 is intended to be 'in addition to,' as a backup, and not 'in lieu of' the automatic initiation requirement of Section 4.1."
* Written commitments are contained in docketed correspondence, including responses to Generic Letters.* "Staff positions" are explicit interpretations, and are contained in documents such as Generic Letters, and to which a licensee has previously committed."Positions contained in these documents are not considered applicable staff positions to the extent that the staff has, in a previous licensing or inspection action, tacitly or explicitly excepted the licensee from part or all of the position." Enclosure 1 Page 10 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception"Imposition of a staff position to which a licensee has previously been excepted is a backfit." (NUREG-1409, Appendix D, page 13 "NRC Manual Chapter 0514, NRC Program for Plant-Specific Backfitting of Nuclear Power Plants")(Emphasis added)Also, NUREG-1409, Section 3.3, "Plant-Specific Backfits," states at question 7 (emphasis added): "If the staff previously exempted a licensee from a legal requirement or approved position, it is not applicable to that licensee for purposes of backfit consideration." The 1977 letter is not a regulation, order or condition in the HNP licenses.
Again, for the HNP degraded grid protective scheme, manual action by operators is taken before the plant conditions for automatic actuation are reached.
The 1977 letter's provisions with respect to degraded grid and compensatory manual actions at HNP may not be considered an applicable staff position for purposes of imposing a backfit because the licensee was previously excepted.Nonetheless, today the staff maintains, on page 7 of the September 29, 2011 NRC Evaluation of Licensee Backfit Appeal (emphasis added), that: "...although GDC-17 and 10 CFR 50.55a(h)(2) do not expressly prohibit manual actions in all situations and make reference to the use of manual actions for certain situations, the NRC's position has been that the protection feature be automatic, which is not being met at HNP." Accordingly, the NRC staff invocation of the compliance backfit exception to include modifications which are necessary to make a facility consistent with staff positions to which a licensee has previously been excepted is inconsistent with NRC guidance relative to application of the backfit rule.Instructive for the EDO on this appeal is a particular question and response found in NRC staff guidance (NUREG-1409, Section 3.1, question 7). The answer addresses three cases, one involving an explicit exemption 3 from a legal requirement or approved staff position and the other two involving the staff's"tacit" approval associated with previous staff review of a licensee action or program or due to the passage of time. In both "tacit"cases, if the staff were to require additional action by the licensee, the staff's action would be a backfit, but might not be a compliance backfit (or meet other exceptions listed in the backfit 3 Today the staff reads the guidance narrowly, as applicable to staff exemptions in accordance with 10 CFR 50.12. However, an exemption under that provision is limited to an "exemption from the requirements of the regulations of this part" and not applicable to exemptions from staff positions.
Specifically, the November 22, 1993 GPC letter (Enc. 3, Item 6), the July 1, 1994 GPC letter to the NRC (Enc. 3, Item 7), the January 10, 1995 NRC meeting notes (Enc. 3, Item 8), and February 23, 1995 NRC SER (Enc. 3, Item 9) address in detail the plant's response to degraded grid conditions, the setpoints for automatic disconnection, and anticipatory alarms and potential manual actions at Enclosure 1 Page 8 of 12
Enclosure 1 Page 11 of 12 Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception rule). "Explicit exemption would be done formally in writing." 4 An approved staff position, then, for which the licensee has been explicitly exempted, "is not applicable to the licensee for the purpose of backfit consideration." In other words, such a staff position cannot be relied upon by the current staff for a compliance backfit exception, as urged by the current staff.Accordingly, the compliance exception was created to address situations when known and established standards were overlooked or requirements were not imposed due to mistakes of fact or inaccurate or incomplete information.
 
Such is not the case in this appeal. The backfit rule requires that the staff be bound by its"previous licensing actions.. .that explicitly excepted the licensee from part or all of the position." The history of the approval of the 1995 deviation and license amendment also demonstrate that the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior enforcement action and, as a matter of policy, the staff should not reopen that closed action. In accordance with the NRC's Enforcement Policy, Section 2.3.8, "special circumstances" must be present for the staff to "reopen" closed enforcement actions. Special circumstances do not exist here, when the staff had extensive and detailed information at the time it made its enforcement decision.Conclusion In conclusion, SNC appeals to the EDO regarding the staff's determination that a backfit is warranted and to the staff's application of the 10 CFR 50.109(a)(4)(i),"compliance exception," to avoid the obligation to perform a cost-justified substantial safety benefit analysis prior to imposition of a backfit. The NRC licensed HNP for its current degraded voltage protection scheme including mandating provisions and conditions in its Technical Specifications.
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception below 92%. An automatic degraded grid trip for voltages below 88.34% (currently 78.8%) of bus voltage was approved by the NRC staff for the automatic disconnect, provided that the anticipatory alarm relays and degraded voltage relays came into the Technical Specifications. (The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enc. 2.)
In addition, SNC submits there is documentation which supports that the 1995 staff did not"erroneously approve the use of manual action" to respond to degraded grid conditions.
Manual action instead of automatic trip is applicable, then, only to a narrow band of voltages above the automatic trip level. Once the trip setpoint is reached, the actuation of the protection system goes to completion without manual intervention, in accordance with IEEE Std. 279-1971 at §4.16 on pg. 10. No regulation, order or commitment precludes anticipatory manual action for degraded grid voltages as a component of a plant's degraded grid configuration.
At issue here is a difference in professional opinions between the 1995 staff and the current staff. Finally, there are no new technical requirements, rules or regulations which would justify a change in the NRC staff's position.Therefore, SNC has concluded that the HNP degraded voltage protection scheme continues to meet the requirements of GDC-17 and 10 CFR 50.55a(h)(2) and no compliance backfit is warranted.
Ill. The "compliance backfit exception" is not applicable to the change in NRC staff positions in this matter.
4 Note the guidance does not reference "specific exemptions" (the phrase used in 10 CFR 50.12), or 50.12 (or its predecessor) or any particular precondition but "formal." "Explicit approval" could be provided in an inspection report, but "usually made in a safety evaluation reports rather than inspection reports." NUREG-1 409, Section 3.3, question 1.The licensee's July 1, 1994 letter stated, "...GPC requests formal NRR staff review and approval of this deviation." (TAC No. 80948).Enclosure 1 Page 12 of 12 Edwin I. Hatch Nuclear Plant Enclosure 2 Loss of Power Instrumentation Surveillance Requirements Edwin I. Hatch Nuclear Plant Loss of Power Instrumentation Surveillance Requirements LOP Instrumentation Surveillance Requirements Source: Hatch Units 1 & 2 Technical Specifications Table 3.3.8.1-1 REQUIRED ALLOWABLE CHANNELS SURVEILLANCE VALUE FUNCTION PER REQUIREMENTS FUNCTION (% 4.16 kV).4.16 kV Emegency Bus Undervoltage (Loss of Voltage)a.Bus Undervoltage 2 SR 3.3.8.1.2  
        "The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact." See 50 Fed. Reg.
> 2800 V (67.3%)SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.2 s 6.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4 2. 4.16 kV Emegency Bus Undervoltage (Degraded Voltage)a.Bus Undervoltage 2 SR 3.3.8.1.2  
38097, 38103 (Sept. 20, 1985).
> 3280 V (78.8%)SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.2 s 21.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4 3. 4.16 kV Emegency Bus Undervoltage (Annunciation) a.Bus Undervoltage 2 SR 3.3.8.1.1  
Whether the NRC staff's invocation of the compliance backfit exception in 10 CFR 50.109(a)(4)(i) supports the backfit discussed in its May 25, 2011 letter depends on whether that exception may be used to avoid a cost-justified substantial safety backfit analysis when the NRC staff changes its position regarding what is necessary to comply with a regulatory requirement, as opposed to whether a facility or license is in compliance with a clearly stated regulatory requirement. As stated in 10 CFR 50.109(a)(4)(i), the exception applies where "a modification is necessary to bring a facility into compliance with a license or the rules or orders of the Commission, or into conformance with written commitments by the licensee." The backfit imposed by the NRC staff's May 25, 2011 letter incorrectly relies on the "compliance backfit exception" to avoid the obligation of the NRC staff to perform a cost-justified substantial safety backfit analysis.
>3825 V (92%)SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.1 5 65 seconds SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 Enclosure 2 Page 1 of 1 Edwin I. Hatch Nuclear Plant Enclosure 3 Appeal to the EDO: Reference Documents Edwin I. Hatch Nuclear Plant Appeal to the EDO: Reference Documents 1. February, 1982 EGG Report to NRC  
The NRC staff's rationale for invoking the compliance backfit exception is that it disagrees with the NRC's 1995 determination that the HNP degraded grid protection system satisfies both 10 CFR 50.55a(h)(2) and GDC-17. As stated on page 3 of the Sept. 29, 2011 NRC Evaluation of Licensee Backf it Appeal:
        "...the backfitting action is necessary for compliance with GDC-17 and 10 CFR 50.55a(h)(2) and is consistent with applicable guidance and practices in effect at the time the NRC staff erroneously approved the use of manual actions for controlling voltages at HNP."
This statement is instructive. First, the NRC staff says that the backfitting action is necessary for compliance with two specific regulations. As set forth above, however, the NRC in 1995 expressly addressed the compliance of the HNP Enclosure 1 Page 9 of 12
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception system under the same regulations and came to a different conclusion than the NRC staff does today. Because the NRC staff's position in 2011 is not based on the express language of either regulation but on the "intent" of the regulations, the difference of opinion is clearly a change in NRC staff position, not a mistake or error by the NRC in 1995.
The NRC staff's invocation of the compliance backfit exception under these circumstances would improperly enlarge the scope of the exception from "omissions or mistakes of fact" to encompass alleged "approval errors" for deviations to staff positions which were based on accurate and complete facts.
Application of the compliance backfit exception in this way would be inconsistent with the clear language and intent of the backfit rule. 'The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact. It should be noted that new or modified interpretations of what constitutes compliance would not fall within the exception and would require a backfit analysis and application of the standard." See 50 Fed. Reg. 38097, 38103 (Sept.
20, 1985). See also NUREG 1409 § 3.1 at pg. 12 (which cites this statement from the Federal Register notice).
Second, the NRC staff says that backfitting action is "consistent with" historic guidance. NRC guidance documents are not regulations. They have not gone through the Administrative Procedures Act process and the vetting appropriate for rules. For example, Branch Technical Position (BTP) 8-6 (Rev. 3, March, 2007),
"Adequacy of Station Electric Distribution Voltages," is found in NUREG 0800, Chapter 8 as part of the Standard Review Plan. The first footnote in BTP 8-6 includes: "...the Standard Review Plan is not a substitute for the NRC's regulations, and compliance with it is not required." Thus, the BTP is not a regulation. "Consistent with" is not equal to "mandated by."
Important distinctions apply to "legal requirements", "commitments" and "staff positions" in the context of backfits:
* Legal requirements are contained in explicit regulations, orders, and plant licenses (amendments, conditions, technical specifications).
* Written commitments are contained in docketed correspondence, including responses to Generic Letters.
*   "Staff positions" are explicit interpretations, and are contained in documents such as Generic Letters, and to which a licensee has previously committed.
        "Positions contained in these documents are not considered applicable staff positions to the extent that the staff has, in a previous licensing or inspection action, tacitly or explicitly excepted the licensee from part or all of the position."
Enclosure 1 Page 10 of 12
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception "Imposition of a staff position to which a licensee has previously been excepted is a backfit."
(NUREG-1409, Appendix D, page 13 "NRC Manual Chapter 0514, NRC Program for Plant-Specific Backfitting of Nuclear Power Plants")
(Emphasis added)
Also, NUREG-1409, Section 3.3, "Plant-Specific Backfits," states at question 7 (emphasis added):
              "If the staff previously exempted a licensee from a legal requirement or approved position, it is not applicable to that licensee for purposes of backfit consideration."
The 1977 letter is not a regulation, order or condition in the HNP licenses. The 1977 letter's provisions with respect to degraded grid and compensatory manual actions at HNP may not be considered an applicable staff position for purposes of imposing a backfit because the licensee was previously excepted.
Nonetheless, today the staff maintains, on page 7 of the September 29, 2011 NRC Evaluation of Licensee Backfit Appeal (emphasis added), that:
        "...although GDC-17 and 10 CFR 50.55a(h)(2) do not expressly prohibit manual actions in all situations and make reference to the use of manual actions for certain situations, the NRC's position has been that the protection feature be automatic, which is not being met at HNP."
Accordingly, the NRC staff invocation of the compliance backfit exception to include modifications which are necessary to make a facility consistent with staff positions to which a licensee has previously been excepted is inconsistent with NRC guidance relative to application of the backfit rule.
Instructive for the EDO on this appeal is a particular question and response found in NRC staff guidance (NUREG-1409, Section 3.1, question 7). The answer addresses three cases, one involving an explicit exemption 3 from a legal requirement or approved staff position and the other two involving the staff's "tacit" approval associated with previous staff review of a licensee action or program or due to the passage of time. In both "tacit"cases, if the staff were to require additional action by the licensee, the staff's action would be a backfit, but might not be a compliance backfit (or meet other exceptions listed in the backfit 3 Today the staff reads the guidance narrowly, as applicable to staff exemptions in accordance with 10 CFR 50.12. However, an exemption under that provision is limited to an "exemption from the requirements of the regulationsof this part" and not applicable to exemptions from staff positions.
Enclosure 1 Page 11 of 12
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception rule). "Explicit exemption would be done formally in writing."4 An approved staff position, then, for which the licensee has been explicitly exempted, "is not applicable to the licensee for the purpose of backfit consideration." In other words, such a staff position cannot be relied upon by the current staff for a compliance backfit exception, as urged by the current staff.
Accordingly, the compliance exception was created to address situations when known and established standards were overlooked or requirements were not imposed due to mistakes of fact or inaccurate or incomplete information. Such is not the case in this appeal. The backfit rule requires that the staff be bound by its "previous licensing actions.. .that explicitly excepted the licensee from part or all of the position." The history of the approval of the 1995 deviation and license amendment also demonstrate that the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior enforcement action and, as a matter of policy, the staff should not reopen that closed action. In accordance with the NRC's Enforcement Policy, Section 2.3.8, "special circumstances" must be present for the staff to "reopen" closed enforcement actions. Special circumstances do not exist here, when the staff had extensive and detailed information at the time it made its enforcement decision.
Conclusion In conclusion, SNC appeals to the EDO regarding the staff's determination that a backfit is warranted and to the staff's application of the 10 CFR 50.109(a)(4)(i),
"compliance exception," to avoid the obligation to perform a cost-justified substantial safety benefit analysis prior to imposition of a backfit. The NRC licensed HNP for its current degraded voltage protection scheme including mandating provisions and conditions in its Technical Specifications. In addition, SNC submits there is documentation which supports that the 1995 staff did not "erroneously approve the use of manual action" to respond to degraded grid conditions. At issue here is a difference in professional opinions between the 1995 staff and the current staff. Finally, there are no new technical requirements, rules or regulations which would justify a change in the NRC staff's position.
Therefore, SNC has concluded that the HNP degraded voltage protection scheme continues to meet the requirements of GDC-17 and 10 CFR 50.55a(h)(2) and no compliance backfit is warranted.
4 Note the guidance does not reference "specific exemptions" (the phrase used in 10 CFR 50.12), or 50.12 (or its predecessor) or any particular precondition but "formal." "Explicit approval" could be provided in an inspection report, but "usually made in a safety evaluation reports rather than inspection reports." NUREG-1 409, Section 3.3, question 1.
The licensee's July 1, 1994 letter stated, "...GPC requests formal NRR staff review and approval of this deviation." (TAC No. 80948).
Enclosure 1 Page 12 of 12
 
Edwin I. Hatch Nuclear Plant Enclosure 2 Loss of Power Instrumentation Surveillance Requirements
 
Edwin I. Hatch Nuclear Plant Loss of Power Instrumentation Surveillance Requirements LOP Instrumentation Surveillance Requirements Source: Hatch Units 1 & 2 Technical Specifications Table 3.3.8.1-1 REQUIRED                             ALLOWABLE CHANNELS       SURVEILLANCE             VALUE FUNCTION                       PER         REQUIREMENTS FUNCTION                             (% 4.16 kV)
  .4.16 kV Emegency Bus Undervoltage (Loss of Voltage) a.Bus Undervoltage                       2           SR 3.3.8.1.2   > 2800 V (67.3%)
SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay                             2           SR 3.3.8.1.2   s 6.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4
: 2. 4.16 kV Emegency Bus Undervoltage (Degraded Voltage) a.Bus Undervoltage                       2           SR 3.3.8.1.2   > 3280 V (78.8%)
SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay                             2           SR 3.3.8.1.2   s 21.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4
: 3. 4.16 kV Emegency Bus Undervoltage (Annunciation) a.Bus Undervoltage                     2           SR 3.3.8.1.1   >3825 V (92%)
SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay                           2           SR 3.3.8.1.1     5 65 seconds SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 Enclosure 2 Page 1 of 1
 
Edwin I. Hatch Nuclear Plant Enclosure 3 Appeal to the EDO:
Reference Documents
 
Edwin I. Hatch Nuclear Plant Appeal to the EDO: Reference Documents
: 1. February, 1982 EGG Report to NRC


==Subject:==
==Subject:==
Degraded Grid Protection for Class 1 E Power Systems 2. August 22, 1991 -NRC Inspection Report 50-321/91-202  
Degraded Grid Protection for Class 1 E Power Systems
& 50-366/91-202
: 2. August 22, 1991 - NRC Inspection Report 50-321/91-202 & 50-366/91-202
: 3. October 7, 1991 -Notice of Violation; NRC Inspection Report 50-321/91-202 & 50-366/91-202
: 3. October 7, 1991 - Notice of Violation; NRC Inspection Report 50-321/91-202 & 50-366/91-202
: 4. November 6, 1991 -GPC Letter to NRC  
: 4. November 6, 1991 -GPC     Letter to NRC


==Subject:==
==Subject:==
Response to Notice of Violation 5. November 16,1992 -GPC meeting with NRC  
Response to Notice of Violation
: 5. November 16,1992 - GPC meeting with NRC


==Subject:==
==Subject:==
HNP Degraded Grid Issues 6. November 22, 1993 -GPC letter to NRC  
HNP Degraded Grid Issues
: 6. November 22, 1993 - GPC letter to NRC


==Subject:==
==Subject:==
Degraded Grid Protection
Degraded Grid Protection
: 7. July 1, 1994 -GPC letter to NRC  
: 7. July 1, 1994 - GPC letter to NRC


==Subject:==
==Subject:==
Degraded Grid Protection
Degraded Grid Protection
: 8. January 10, 1995 -NRC letter to GPC  
: 8. January 10, 1995 - NRC letter to GPC


==Subject:==
==Subject:==
Summary of December 7, 1994 meeting 9. February 23, 1995 -NRC letter to G PC  
Summary of December 7, 1994 meeting
: 9. February 23, 1995 - NRC letter to G PC


==Subject:==
==Subject:==
SER for Degraded Grid Voltage Relay Setpoints Enclosure 3 Page 1 of 1 A)eeid eac ..I4- 45tauo F.-.iG-EA-5754 FEBRUARY 1982 DEGRADED GRID PROTF!TION FOR CLASS 1E POWER SYSTEMS, EDWIN I. HATCH S;-%.4,EAR POWER PLANT, UNIT NOS. 1 AND 2 A. C. Udy U.S. Department of Energy IdahIo Opratlon$
SER for Degraded Grid Voltage Relay Setpoints Enclosure 3 Page 1 of 1
Office
 
* Idaho National Engineering Laboratory Ralf/' eaK A)!;t e A;f r/ S C11-,-i i I ,-. =11111110 011%awalift man" BM W an*O= .-414nwww TI ns Is an informal rtpofl Intended for use as a preliminary or working document f.*pared for thr u. S. Nuclear F&;.Under DOE.Lont:-
A)eeid             eac           .. I4-                         45tauo               F.             -.iG-EA-5754 FEBRUARY 1982 DEGRADED GRID PROTF!TION FOR CLASS 1E POWER SYSTEMS, Ralf EDWIN I. HATCH S;-%.4,EAR POWER PLANT, UNIT NOS. 1 AND 2                                           /'eaK A)!;t e A;f r/ S C11-,
FIN No. A6429 U;'-107 8204-26 Pz' ':LS q;Z04140575 PDR atc Domi SS on Ac716Di n E~
A. C. Udy U.S. Department of Energy IdahIo Opratlon$ Office
:- E .. F'. _ I.. ..' -.. .M" '-4 d~m o. fgn H S IT 64 6tf INTERIM REPORT ACCeSsion No .Report No _Contract Program o* Project Tile: Selected Operating Reactor Issues Progra.m (Ill)Subje"t of tNa Document;Degraded Grid Protection for Class lE Power SystemS, Edwin I. Hatch Nuclear Power Plant, Unit Nos. 1 and 2 Type ol Document Informal Report Author(s), A. C. Udy Oate of Oocument.February 1982 Responsible NRC/DOE Individual and NRCIDO£ Office r Divitskm: R. L. Prevatte, Division of Systems Integration, NRC This dCoeument was prepared primarily for prelimitary or internal use. It has not received full review and approval.
* Idaho National Engineering Laboratory 11111110 011%awalift man" BM W an
Since there may be substantive changes. this document should not be considered Vreial.EG&G Idaho Inc Idaho Falls. Idaho $3415 Prepared for the 4 U.S. Nuclear Regulatory CommissiOn Washington, D.C.Undier DOE Contract No. DE0CQ7.?6I10167o NRC FIN No .--INTERIM REPORT 61 1011 M, W^-011 'A' 0451 J V DEGRADED GRID PROTECTION FOR CLASS 1E POWER SYSTEMS EDWIN I. HATCH NUCLEAR POWER PLANT, UNIT NOS. 1 AND 2 February 198?A. C. Udy Reliabtlity and Statistics Branch Engineering Analysis Division EG&G Idaho, Inc.0 TAC Nos. 10026 and 11262 Docket Nos. 50-321 and 50-366 IN , -b ABSTRACT This EG&G Idaho, Inc. report reviews the susceptibility of the safety.related electrical equipment at the Edwin I. Hatch Nuclear Power Plant to a Sustained degradation of the offsite power sources.FOREWORD This report is supplied as part of the "Selected Operating Reactor Issues Programs (III)" being conducted for the U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Division of Licensing, by EG&G Idaho, Inc., Reliability and Statistics Branch.The U.S. Nuclear Aegulatory Commission funded the work under authorization BMR ?0 19 0) 06, Fin No. A6429.Ii.-. m SEINT BY: :.op-"1 C~e lel- , l6-Z' : IL: _ ' ,. .... ,:,: .;:.CONTENTS.O INTRODUCTION
                                                                              *O=                       . -414nwww i  I        ,-.          -i              =
.........................................
TIns Is an informal rtpofl Intended for use as a preliminary or working document f.*pared for thr
.........
: u. S. Nuclear F&;. atc            Domi SS on Under DOE.Lont:-                 Ac716Di FIN No. A6429 n E~
I 2.0 DESIGN BASE CR1 7?RIA ... ............
U;'-107           8204-26 Pz'   ':LS q;Z04140575               PDR
...........
 
.................
:- E .. _
1 3.0 EVALUATION
F'.     :..*-*'-*ne,'* I..                     .. ' -..                         '-4 .4*  *205        .M"   070* d~m o. ~i*.
......................................................
fgn   H   S     IT   64     6tf INTERIM REPORT ACCeSsion No     .
I 3.1 Undervoltage Protection
Report No _
..........................
Contract Program o* Project Tile:
2 3.2 'odtflcations
Selected Operating Reactor Issues Progra.m (Ill)
..............................,s., 2 3.3 01scuss ion .................
Subje"t of tNa Document; Degraded Grid Protection for Class lE Power SystemS, Edwin I. Hatch Nuclear Power Plant, Unit Nos. 1 and 2 Type ol Document Informal Report Author(s),
....... ...... 3
A. C. Udy Oate of Oocument.
February 1982 Responsible NRC/DOE Individual and NRCIDO£ Office r Divitskm:
R. L. Prevatte, Division of Systems Integration,                     NRC This dCoeument was prepared primarily for prelimitary or internal use. It has not received full review and approval. Since there may be substantive changes. this document should not be considered Vreial.
EG&G Idaho Inc Idaho Falls. Idaho $3415 Prepared for the 4                                                 U.S. Nuclear Regulatory CommissiOn Washington, D.C.
Undier DOE Contract No. DE0CQ7.?6I10167o NRC FIN No       -      9-.--
INTERIM REPORT 1011                                        61 W^-011 'A' M,


==4.0 CONCLUSION==
0451 J V
S
DEGRADED GRID PROTECTION FOR CLASS 1E POWER SYSTEMS EDWIN I. HATCH NUCLEAR POWER PLANT, UNIT NOS. 1 AND 2 February 198?
.....................................................
A. C. Udy Reliabtlity and Statistics Branch Engineering Analysis Division EG&G Idaho, Inc.
5 5 .0 REFERENCES
0 TAC Nos. 10026 and 11262 Docket Nos. 50-321 and 50-366
.....................  
 
...............
IN , -
5* e Fe a as e ee e. .e I j i ~ ~ t e it B e e .o l o 0 Si' 5ENT B'(:CoPj Oeneral SENT B~: ~ Ieneral06-26-91 i i: 46)4 2029445474-i 0 7 6ý8~~205 8?0 6103 414 DEGRADED GRID F t nTECIION FOR CLASS IE POWER SYSTEMS EDWIN I. HATCH NUCLEAR -9WER FLANT, UNIT MOS. 1 AND 2 1.0 TNTRODUCTION On June 2, 1977, the NRC requested the Georgia Power Company (GPC) to assess the susceptib~lity of the safety-related electrical equipment at the Edwin I. Hatch Nuclear Plant Unit 1 to a sustained voltage degradation of the offs te source and interaction of the offslte and ons!,e emergency power Systems. The letter contained three positions with which the current design of the plant was to be compared.
b ABSTRACT This EG&G Idaho, Inc. report reviews the susceptibility of the safety.
After comparing the current destgn to the staff positions.
related electrical equipment at the Edwin I. Hatch Nuclear Power Plant to a Sustained degradation of the offsite power sources.
GPC was required to either propose modifications to satisf the positions and criteria or furnish an analysis to substantiate that t4e existing facility design has equivalent capabilities.
FOREWORD This report is supplied as part of the "Selected Operating Reactor Issues Programs (III)" being conducted for the U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Division of Licensing, by EG&G Idaho, Inc., Reliability and Statistics Branch.
GPC replied to the NRC letter on July 22. 1977,2 GPC supplied addi-tional information a~d technical specification changes on Ortober g, 19803 and on May 21, 1981. On October 2, 1981, GPC submittal modified techni-cal spe:-, ication changes fcr Unit No. I and similar technical specifica-tion changes for Unti No. 2.- This submittal had a typing error corrected on December 2, 1981,° Adoitional information Isfound in GPC letter5 dated September 17, 1976,' and January 12, 1982.° On January 26, 1981.GPC suimitted all of the revised pages for the Unit 1 technical tions..2.0 DESIGN BASE CRITERIA The design base criteria that were applied In determining the accepta-bility of the system modifications to protect the safety-related equipment from a sustained degradation of the offsite grid are: 1. General Design Criterion 17 (GDC 17), "Electrical Power Systems," of Appendix A, "General D1t 8 gn Criteria for Nuclear Prwer Plants," of 10 CFR 50 2. IEEE Standar' 279-1971, "Criteria fL' ¶otection Systems for Nuclear Power Generating Stations" 3. IEEE Standard 308-1974, "Class 1E 2wer Systems for Nuclear Power Generating Stations" 4. Staff positions as detailed In a letter sent to the licensee, dated June 3, 1977 ANSI Standard C84.1-1977, "Voltage Ratingi for Electri-cal Power Systems and Equipment (60 HZ).* 3 3.c 4LUATION.This section provides, In Subsection 3.1, a brief description of existing und- age protection at the Hatch Station; in Subsection 3.,2 a descriptior
The U.S. Nuclear Aegulatory Commission funded the work under authorization BMR ?0 19 0) 06, Fin No. A6429.
'licensee's proposed scheme for the ..econd-level und..voltage prc on; and in Subsection 3.3, a discussion of how the system meets the , , ri base criteria.I F I111 ______,_ý!'-
Ii
4 4 3.1 Existing Undervoltage Protection.
                    .-.     m
The previous de'ign utilized four undervoltage relays on each 41OVI Mass 1E emergency hus. They were arranged in a one-out-of-two-taken-twice logic scheme. Tie relays were set to operate at a voltage of 2912V (70%). These relays were used to sense a loss of offslte power. Should the voltage on the Class 1E buses fall the setpofnt, autoeatic fast transfer is initiated to the alternate
 
-source by this relay logic and the diesel generators are started. If the alternate source is not available, the buses are load-stripped and the preferred and alternate source breakers are tripped and locked-out.
SEINT BY: :.op-"1 C~e lel- , l6-Z'                    :      IL:                                          _ '            ,.                           .... ,:,:.   ;:.
As the diesel generators reach 90% of rated voltage and frequency, the diesel.generator bus breaker iS automatically closed. The undervoltage condition is also annunciated in the main control room.This system disables the load-shed featurc once the Class lE buses are being supplied by the diesel generators.
CONTENTS
Prior to the modification pro-rosed in 1976, this was not disabled.5 Non-essential loads, howeve, are load-shed when an accident signal exists whether the Class IE buses are being supplied from the offsite or the onsite power sources.3.2 Modifications.
                    .O    INTRODUCTION .........................................                                                         .........               I 2.0      DESIGN BASE CR1 7?RIA ... ............                            ...........                .................                        1 3.0       EVALUATION ......................................................                                                                      I 3.1    E*xsting Undervoltage Protection ..........................                                                                    2 3.2     'odtflcations ..............................                                                                  ,s.,             2 3.3    01scuss ion .................                                            .          ......                  .....
To protect the Class 1E safety-relate' equipment from the errects or a degraded grid condition GPC has proposed ,:hanging the setpoints on the existing undervoltage relays. The relays used are Westinghouse type CV-7 inverse-time undervoltaqe relays. The two degraded voltage relays, arranged In a two-out-of-two 1kglc, will have a nominal'Pint of 3?80V (78.81 of bus voltage) with a time delay of less than or 4ual to 21.5 seconds. When a loss-of-voltage occurs, two other relays.also utilizing a two-out-of-two logic, will operate at a setpoint Of greater than or equal to 2800V (67.3% of bus voltage) with a time delay of less than or equal to 6.5 seconds. GPC has submitted a diagram showing the relay charateristics both above and below these nominal values.8 Upon a trip signal from both degraded voltage relays or both loss-of-voltage relays the sequence of events will be as stated In Subsection 3.1, except that the operation of any one of the four mentioned relays will initiate the start of the diesel generator associated with that bus. The voltages and time delays specified are one point on the calibration curve for that relay. The relays operate with less time delay at lower voltages, and a greater time ,!tlay at hiqher voltages.
                                                                                                                                                .                3
GPC has shown that the operating characteristics of the relays will not spuriously trip the Class IE busct from offsite power for all expected combinations of offilte grid voltage and unit loadS.Load-shedding is blocked once the diesel generator is supplying p7,er to its Class lE bus, except for non-essential loads, by use of a "b" co.-tact of the diesel-;enerator breaker. The lad shedding is reinstated should the diesel generator breaker subsequently reopen. AS stated above, this Is already incorporated in the existing logic circuit.Proposed changes to the plant's technical specifications, adding the surveillance requirements, allowable limits for the setpoint and time delay, and limiting conditions for operation for the second-level undervoltage monitors, were also furnished by the licensee.
 
Bases for limiting condi-tions of operation as well as bases for surveillance requirements per-taining to these relays were also included in the technical specification changes. I 2 SENT BY:CoPY Oeneral SEN B:Coy eneal06-26-91 11:E50A 2029445474-ý 205 870 6100 I#15 3.3 Discussion.
==4.0      CONCLUSION==
The first position of the NRC staff letter 1 required that a secoR level of undervoltage protection for the onsite Power system be prokided.
S .....................................................                                                                   5 5 .0 REFERENCES              .....................                                        ...............                                     5
The letter stipulates other criteria that the undervoltage protection must meet. Each criterion Is restated below followed by a dis-cussion regarding the licensee's compliance with that criterion.
* Fe              e          a   as  e ee    e.  .         e I      j  i  ~~    t  e it  B    e              e .o      l o 0 Si'
I. 'The selection of voltage and time setpolnts shall be determined from an analysis of the voltage requireents of the safety-related loads at all onsite distribution system levelS." GPC has analyzed for the voltage requirments for the sofety-Stlated loads at all onsite distribution system levels. These studies have contributed to the selection of the proposed relay settings.2. "The voltage protection shall include coincidence logic to pre-clude spurious trips of the offsite power sources." The relay logic is arranged In'a tw-out-of-two logic that satisfies this criterion.
 
: 3. "The time delay selected shall be based on the following conditions:
5ENT B'(:CoPj Oeneral                SENT ~ Ieneral06-26-91 B~:    i i: 46)4          2029445474-i        0 8?0 205  7 6103 6ý8~~ 414 DEGRADED GRID Ft nTECIION FOR CLASS IE POWER SYSTEMS EDWIN I. HATCH NUCLEAR -9WER FLANT, UNIT MOS. 1 AND 2 1.0  TNTRODUCTION On June 2, 1977, the NRC requested the Georgia Power Company (GPC) to assess the susceptib~lity of the safety-related electrical equipment at the Edwin I. Hatch Nuclear Plant Unit 1 to a sustained voltage degradation of the offs te source and interaction of the offslte and ons!,e emergency power Systems. The letter contained three positions with which the current design of the plant was to be compared. After comparing the current destgn to the staff positions. GPC was required to either propose modifications to satisf the positions and criteria or furnish an analysis to substantiate that t4e existing facility design has equivalent capabilities.
: 4. The allowable time delay, including margin, shll not exceed'the maximum time delay that is assumed in the FSAR accident analysis.I The bases for limiting conditions of operation submitted by the licensee states that the proposed time delay.including margin, does not exceed the maximum time delay as analyzed in the FSMR.The proposed time delay will not be the cause of any thermal damage to the safety-related equipment.
GPC replied to the NRC letter on July 22. 1977,2 GPC supplied addi-tional information a~d technical specification changes on Ortober g, 19803 and on May 21, 1981.       On October 2, 1981, GPC submittal modified techni-cal spe:-, ication changes fcr Unit No. I and similar technical specifica-tion changes for Unti No. 2.- This submittal had a typing error corrected on December 2, 1981,° Adoitional information Isfound in GPC letter5 dated September 17, 1976,' and January 12, 1982.° On January 26, 1981.
The equipment is rated to operate at the setpoitnt voltage for in excess of 30 seconds.b. "The time delay shall minimize the effect of short-duration disturbances fram reducins the unavailability of the offsIte power source(s)." The licensee's proposed time delay characteristics provide a time delay long enough to override any short inconsequen-tial grid disturbances.
GPC suimitted all of the revised pages for the Unit 1 technical specif*
Any voltage dips caused from the starting of large motors will not trip the offslte sou'-P C. "The allowable time duration of a degraded voltage condition at all distribution system levels shill not result in fail-ure of safety systems or components." A review Of the licensee's voltage analysis 3 indicates that the time delay will not cause any failures of the 3 SENT BY:CoPV General SENT Y~CoY Genr'al06-26-91i 1:Se5Ol 20294454'i4-)0 7 60 1 205 870 6108 #16'safety-related equipment since the relay, characteristics will disconnect a degraded source of AC power before the Stall rating o. in.t Pu- pvent 1 exCeeded.4. "The voltage monwt-t 3tomiacally Inttiate the disconnec-tion of offsite whenever the voltage setpoint and time-delay limit. ,: "xceeded." A review of the icensee's proposal substantiates that this cri.terion Is met.5. 'The voltage monitors shall be designed to satisfy the require.meits of IEEE Standard 279-1971.The licensee has stated in his submittal that all circuits associated witN Jhe undervoltap relays meet IEEE Stan-Olard 279-1971.
tions..
.°6. "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip SetpointS with minima and maximum limits, and allowable values for the Second-level voltage protection monitors," The latest draft proposal for technical specification changes ', includes all of the required items except for Instru-ment check. The instrument check is normally done by. vertf ng that normal voltage is present at the input to each undervoltage relay. The Hatch station does not have voltmeters or indicators at this location, therefore the Instrument check is not applicable.
2.0 DESIGN BASE CRITERIA The design base criteria that were applied In determining the accepta-bility of the system modifications to protect the safety-related equipment from a sustained degradation of the offsite grid are:
Analyses have been performed which assurte that the range between the maximum and the minimum settings (allowable limits) will not be the cause of spurious trips of offsite power nor will they allow the voltage to be so low as to allow damage to the safety equipment.
: 1. General Design Criterion 17 (GDC 17), "Electrical Power Systems," of Appendix A, "General D1t8 gn Criteria for Nuclear Prwer Plants," of 10 CFR 50
The second NRC staff position requires that the system design auto-matically prevent load-shedding of the emergency buses once the onsfte sources are supplying power to all sequenced loads. The load-shedding must also be reinstated if the onsite breakers are tripped.GPN tates that this feature is already incorporated in the circuit design,'P,° A review of the logic circuitry substantiates that the load-shed is blockedby a contact of the dlesel-gentrator breaker. All non-eSsential loads are, however, load-shed when the onsitt source is supplying puwer to the thass 1E buses.The third NRC staff position requires that certain test requirements be added to the technical specifications.
: 2. IEEE Standar' 279-1971, "Criteria fL' ¶otection Systems for Nuclear Power Generating Stations"
These tests were to demonstrate the full-functional operability and independence of the onsite power sources and are to be performed at least once per 18 months during shutdown.
: 3. IEEE Standard 308-1974, "Class 1E 2wer Systems for Nuclear Power Generating Stations"
The tests are to simulate loss of offsite power in conjunction with a simulated safety Injection actuation signal and to simulate interruption and subse-quent reconnection of onuite power sources. These tests verify the proper 4 a -I operation of the load-shed s...tem, the load-shed bypiiss when the emergency diesel generators are supply..q power to their respective buses, and that Lhere IS no adverse Interaction between the onsite and offsIte power sources.The testing procedures proposed by the licensee do comply with this position.
: 4. Staff positions as detailed In a letter sent to the licensee, dated June 3, 1977 ANSI Standard C84.1-1977, "Voltage Ratingi for Electri-cal Power Systems and Equipment (60 HZ).* 3 3.c    4LUATION.
Load-shedding when offsite power Is tripped Is tested. Load-once the diesel generator is supplying the safety buses, is testet,. A simulated loss of the diesel generator and subsequent load-shedding and load-sequencing once the diesel generator iS back on-line ,s tested. The time durations of the tests will verify that the time deley of the undervoltage relays Is sufficient to avoid spurious trips and that the load-shed bypass circuit Is functioning properly.
This section provides, In Subsection 3.1, a brief description of existing und-         age protection at the Hatch Station; in Subsection 3.,2 a descriptior        'licensee's      proposed scheme for the ..econd-level und..
voltage prc        on; and in Subsection 3.3, a discussion of how the system meets the ,, ribase criteria.
I
 
F      I111                              ______,_ý!'-                4 4
3.1  Existing Undervoltage Protection.         The previous de'ign utilized four undervoltage relays on each 41OVI          Mass    1E emergency hus. They were arranged in a one-out-of-two-taken-twice logic scheme. Tie relays were set to operate at a voltage of 2912V (70%).             These relays were used to sense a loss of offslte power. Should the voltage on the Class 1E buses fall the setpofnt, autoeatic fast transfer is initiated to the alternate                    -
source by this relay logic and the diesel generators are started. If the alternate source is not available, the buses are load-stripped and the preferred and alternate source breakers are tripped and locked-out. As the diesel generators reach 90% of rated voltage and frequency, the diesel.
generator bus breaker iS automatically closed. The undervoltage condition is also annunciated in the main control room.
This system disables the load-shed featurc once the Class lE buses are being supplied by the diesel generators. Prior to the modification pro-rosed in 1976, this was not disabled. 5 Non-essential loads, howeve, are load-shed when an accident signal exists whether the Class IE buses are being supplied from the offsite or the onsite power sources.
3.2 Modifications. To protect the Class 1E safety-relate' equipment from the errects or a degraded grid condition GPC has proposed ,:hanging the setpoints on the existing undervoltage relays. The relays used are Westinghouse type CV-7 inverse-time undervoltaqe relays. The two degraded voltage relays, arranged In a two-out-of-two 1kglc, will have a nominal
        'Pint of 3?80V (78.81 of bus voltage) with a time delay of less than or 4ual to 21.5 seconds. When a loss-of-voltage occurs, two other relays.
also utilizing a two-out-of-two logic, will operate at a setpoint Of greater than or equal to 2800V (67.3% of bus voltage) with a time delay of less than or equal to 6.5 seconds. GPC has submitted a diagram showing the relay charateristics both above and below these nominal values. 8 Upon a trip signal from both degraded voltage relays or both loss-of-voltage relays the sequence of events will be as stated In Subsection 3.1, except that the operation of any one of the four mentioned relays will initiate the start of the diesel generator associated with that bus. The voltages and time delays specified are one point on the calibration curve for that relay. The relays operate with less time delay at lower voltages, and a greater time ,!tlay at hiqher voltages. GPC has shown that the operating characteristics of the relays will not spuriously trip the Class IE busct from offsite power for all expected combinations of offilte grid voltage and unit loadS.
Load-shedding is blocked once the diesel generator is supplying p7,er to its Class lE bus, except for non-essential loads, by use of a "b" co.-
tact of the diesel-;enerator breaker. The lad shedding is reinstated should the diesel generator breaker subsequently reopen. AS stated above, this Is already incorporated in the existing logic circuit.
Proposed changes to the plant's technical specifications, adding the surveillance requirements, allowable limits for the setpoint and time delay, and limiting conditions for operation for the second-level undervoltage monitors, were also furnished by the licensee. Bases for limiting condi-tions of operation as well as bases for surveillance requirements per-taining to these relays were also included in the technical specification changes.                                                           I 2
 
SENT BY:CoPY Oeneral              SEN B:Coy eneal06-26-91 11:E50A              2029445474-ý 205 870 6100 I#15 3.3  Discussion.      The first position of the NRC staff letter 1 required that a secoR level of undervoltage protection for the onsite Power system be prokided. The letter stipulates other criteria that the undervoltage protection must meet.        Each criterion Is restated below followed by a dis-cussion regarding the licensee's compliance with that criterion.
I.  'The selection of voltage and time setpolnts shall be determined from an analysis of the voltage requireents of the safety-related loads at all onsite distribution system levelS."
GPC has analyzed for the voltage requirments for the sofety-Stlated loads at all onsite distribution system levels.     These studies have contributed to the selection of the proposed relay settings.
: 2.   "The voltage protection shall include coincidence logic to pre-clude spurious trips of the offsite power sources."
The relay logic is arranged In'a tw-out-of-two logic that satisfies this criterion.
: 3.   "The time delay selected shall be based on the following conditions:
: 4. The allowable time delay, including margin, shll not exceed' the maximum time delay that is assumed in the FSAR accident analysis.I The bases for limiting conditions of operation submitted by the licensee states that the proposed time delay.
including margin, does not exceed the maximum time delay as analyzed in the FSMR.
The proposed time delay will not be the cause of any thermal damage to the safety-related equipment.        The equipment is rated to operate at the setpoitnt voltage for in excess of 30 seconds.
: b.    "The time delay shall minimize the effect of short-duration disturbances fram reducins the unavailability of the offsIte power source(s)."
The licensee's proposed time delay characteristics provide a time delay long enough to override any short inconsequen-tial grid disturbances.      Any voltage dips caused from the starting of large motors will not trip the offslte sou'-P C.    "The allowable time duration of a degraded voltage condition at all distribution system levels shill not result in fail-ure of safety systems or components."
A review Of the licensee's voltage analysis 3 indicates that the time delay will not cause any failures of the 3
 
SENT BY:CoPV General              SENT Y~CoY Genr'al06-26-91i 1:Se5Ol                20294454'i4-)0          7 60 205 870 6108  1
                                                                                                      #16' safety-related equipment since the relay, characteristics will disconnect a degraded source of AC power before the Stall rating o. in.t Pu- pvent        1  exCeeded.
: 4.  "The voltage monwt-t              3tomiacally Inttiate the disconnec-tion of offsite                      whenever the voltage setpoint and time-delay limit.            ,: "xceeded."
A review of the      icensee's proposal substantiates that this cri.
terion Is met.
: 5.  'The voltage monitors shall be designed to satisfy the require.
meits of IEEE Standard 279-1971.
The licensee has stated in his submittal that all circuits associated witN Jhe undervoltap relays meet IEEE Stan-Olard 279-1971.    .°
: 6.  "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip SetpointS with minima and maximum limits, and allowable values for the Second-level voltage protection monitors,"
The llc¢n*ee's latest draft proposal for technical specification changes ', includes all of the required items except for Instru-ment check. The instrument check is normally done by.vertf ng that normal voltage is present at the input to each undervoltage relay. The Hatch station does not have voltmeters or indicators at this location, therefore the Instrument check is not applicable. Analyses have been performed which assurte that the range between the maximum and the minimum settings (allowable limits) will not be the cause of spurious trips of offsite power nor will they allow the voltage to be so low as to allow damage to the safety equipment.
The second NRC staff position requires that the system design auto-matically prevent load-shedding of the emergency buses once the onsfte sources are supplying power to all sequenced loads. The load-shedding must also be reinstated if the onsite breakers are tripped.
GPN tates that this feature is already incorporated in the circuit design,'P,° A review of the logic circuitry substantiates that the load-shed is blockedby a contact of the dlesel-gentrator breaker. All non-eSsential loads are, however, load-shed when the onsitt source is supplying puwer to the thass 1E buses.
The third NRC staff position requires that certain test requirements be added to the technical specifications.          These tests were to demonstrate the full-functional operability and independence of the onsite power sources and are to be performed at least once per 18 months during shutdown.            The tests are to simulate loss of offsite power in conjunction with a simulated safety Injection actuation signal and to simulate interruption and subse-quent reconnection of onuite power sources.            These tests verify the proper 4
 
a -                                                                              I operation of the load-shed s...tem, the load-shed bypiiss when the emergency diesel generators are supply..q power to their respective buses, and that Lhere IS no adverse Interaction between the onsite and offsIte power sources.
The testing procedures proposed by the licensee do comply with this position. Load-shedding when offsite power Is tripped Is tested. Load-seqL*ncing, once the diesel generator is supplying the safety buses, is testet,. A simulated loss of the diesel generator and subsequent load-shedding and load-sequencing once the diesel generator iS back on-line ,s tested. The time durations of the tests will verify that the time deley of the undervoltage relays Is sufficient to avoid spurious trips and that the load-shed bypass circuit Is functioning properly.
 
==4.0    CONCLUSION==
S Based on the information provided by GPC. it has been determioied that  -
the proposed changes do comply with NRC staff position 1. All of the staff's requirements and design base criteria have been met. The setpoint and time delay will protect the Class 1E equipment from i sustained degraded voltage condition of the offsite power source.
The existing load-shed circuitry does comply with Staff position 2 and will prevent adverse interaction of theoffsite and onsite emergency power systems.
The proposed changes to the technical specifications do adequately test the system modifications and do comply with staff positto'n 3.      The surveillance requirements, limiting conditions for operation, minimum and maximum limits for the trip point, and allowable values satis'y staff position 1.
It is therefore concluded that the mogifications and jhr proposed technical specification changes for Unit I and for Unit 2 ,Ire acceptable. These new setpoints and time delays have been i.nplemiented and It is, therefore, recommended that the changes to the techn.cal* specifica-tions be ipproved atid Implemented at the earliest opportunit.y.
S.0  REFERENCES
: 1. NRC letter, V. Stello tj C. F. Whitmer, GPC,  dated June 2,  1977.
: 2. GPC letter, C. F. Whitmer, to Office of Nuclear Reactor Regulation, NRC, *Emergency Power Systems,  July 22, 1977.
: 3. GPC letter. W. A. Widner to Office of Nuclear React'or Regula.lon. NRC,
          .Response to Request for Additional Information--System Voltage Study,"
October 9, 1980.
J. GPC letter. J. T. Beckham to Office of Nuclear Rector Regulation, NRC, "Emergency Power Systems,' May 21, 1981.
5
 
W "..-
1FNOW                                  I-- dý
  . * .*4
: 5. GPC letter, W. A. Widner to Uirt.-tor of Nuclear Reactor Regulation.
              *,      CEmergency Power Systems,' October 2, 1981.
f6. Gýt letter, .j T. Beckham to Oirector of Nuclear Reactor ReguTation, kC[, 'Revised Technical Speciflcations for Degraded System Vo1tage,*
                .'..*ir 2. 1981.
* CK fitter, C. F. Whitmer to Office of Nuclear Reactor Regu'atton.
H&*C, ^Operation During Degraded Grid Voltage Conditions, September 17, 1976.
: 8. GPC letter, J. T. Beckham to Division of Licensing, MRC, "Adequacy'-of Stationv Electric Distribution System Voltages, Response to RequeSt for Aoditonai Information,' January 12, 1982.
: 9. U'" letter, W. A. Widmer to Director of Nuclear Reactor Regulation,
              ".mergency Power Systems," January 26, 1962.
: 10. General Design Criterion 17. "Electric Power Systems." of. AppendIx A, "General Deslign Criterft for Nuclear Pover Plants," to 10 CFR Part 50, Domestic Licensing of Production and UtiliZation Facilities.%
: 11. IEEE Standard 279-1971, *Criteria for Protection Systems for Nuclear Power Generating Stations."
: 12. IEEE Stafndaru 308-1974, "Standard Criteria for Class IE Power Systems for Nuclear Power Generating Stations.'
: 13. ANSI C84.1-1977. "Voltage Ratings for Electric Power Systems and Equipment (60 HZ)."
4 6


==4.0 CONCLUSION==
              ,UNITED
S Based on the information provided by GPC. it has been determioied that -the proposed changes do comply with NRC staff position 1. All of the staff's requirements and design base criteria have been met. The setpoint and time delay will protect the Class 1E equipment from i sustained degraded voltage condition of the offsite power source.The existing load-shed circuitry does comply with Staff position 2 and will prevent adverse interaction of theoffsite and onsite emergency power systems.The proposed changes to the technical specifications do adequately test the system modifications and do comply with staff positto'n
              ý%A                                   STATES NUCLEAR REGULATORY COMMISSION
: 3. The surveillance requirements, limiting conditions for operation, minimum and maximum limits for the trip point, and allowable values satis'y staff position 1.It is therefore concluded that the mogifications and jhr proposed technical specification changes for Unit I and for Unit 2 ,Ire acceptable.
                £-*                       V wASHIMOT04, 0. C. MQSS,
These new setpoints and time delays have been i.nplemiented and It is, therefore, recommended that the changes to the techn.cal*
          ..                           Aiy T   22,   1991
specifica-tions be ipproved atid Implemented at the earliest opportunit.y.
.ocket     No. SC-321 50-366 Mdr. W. G. Hairston,     III Senior Vice President Georgia Power Company 4C Inverness Center Parkway P.O. Box 1295 Birmingham, Alabama 35201
S.0 REFERENCES
: 1. NRC letter, V. Stello tj C. F. Whitmer, GPC, dated June 2, 1977.2. GPC letter, C. F. Whitmer, to Office of Nuclear Reactor Regulation, NRC, *Emergency Power Systems, July 22, 1977.3. GPC letter. W. A. Widner to Office of Nuclear React'or Regula.lon.
NRC,.Response to Request for Additional Information--System Voltage Study," October 9, 1980.J. GPC letter. J. T. Beckham to Office of Nuclear Rector Regulation, NRC, "Emergency Power Systems,'
May 21, 1981.5 W 1F NOW"..- I -- d ý.* .*4 5. GPC letter, W. A. Widner to Uirt.-tor of Nuclear Reactor Regulation.CEmergency Power Systems,'
October 2, 1981.f6. Gýt letter, .j T. Beckham to Oirector of Nuclear Reactor ReguTation, kC[, 'Revised Technical Speciflcations for Degraded System Vo1tage,*2. 1981.* CK fitter, C. F. Whitmer to Office of Nuclear Reactor Regu'atton.^Operation During Degraded Grid Voltage Conditions, September 17, 1976.8. GPC letter, J. T. Beckham to Division of Licensing, MRC, "Adequacy'-of Stationv Electric Distribution System Voltages, Response to RequeSt for Aoditonai Information,'
January 12, 1982.9. U'" letter, W. A. Widmer to Director of Nuclear Reactor Regulation,".mergency Power Systems," January 26, 1962.10. General Design Criterion
: 17. "Electric Power Systems." of. AppendIx A,"General Deslign Criterft for Nuclear Pover Plants," to 10 CFR Part 50, Domestic Licensing of Production and UtiliZation Facilities.%
: 11. IEEE Standard 279-1971, *Criteria for Protection Systems for Nuclear Power Generating Stations." 12. IEEE Stafndaru 308-1974, "Standard Criteria for Class IE Power Systems for Nuclear Power Generating Stations.'
: 13. ANSI C84.1-1977. "Voltage Ratings for Electric Power Systems and Equipment (60 HZ)." 4 6
ý%A ,UNITED STATES NUCLEAR REGULATORY COMMISSIONV wASHIMOT04, 0. C. MQSS,.. Aiy T 22, 1991.ocket No. SC-321 50-366 Mdr. W. G. Hairston, III Senior Vice President Georgia Power Company 4C Inverness Center Parkway P.O. Box 1295 Birmingham, Alabama 35201  


==Dear Mr. Hairston:==
==Dear Mr. Hairston:==
-SUBJECT; ELECTRICAL DISTRIBUTION SYSTEM FUNCTIONAL INSPECTION-AT-HATCHt (50-32'1/91-202; 50-366/91'202)
 
We are forwarding the repurt of a special electrical distribution system functional inspection (EDSFI) performed June 10 through July 12, 1991, involv-ing activities authorized by Operating License Nos. DPR-57 and NPF-5 for the Hatch Nuclear Plant, Units 1 and 2. This inspeCtion was conducted by tht Special Inspection Branch of the Office of Nuclear Reactor Regulation with the:support of Region II. An exit meeting was held on July 12, 1991, during which-we discussed the team'.s findings with members of your staff.The areas examined during the inspection are discussed in the ew-closed copy ofýour inspection report; The inspection team assessed the desigr,, design imple-mentation and technical support of the electrical distributiun Systen (EDS).The inspection consisted of a selective review of EDS design calculations, relevant procedures, representative records, installed equipment and interview-with engineering and technical support staff.-hE design and design implementation of the EDS at Hatch were generally accept-able. Several strengths were identified in the areas of retrievability of documents, monitoring of grid stability, self-assessment, and competence of the)technical support staff. However, some deficiencies were identified including* inadequate unider voltage protection for plant operation under degraded grid voltage conditions and inadequate coordination of short circuit/fault protec-:tiov devices for safety-related equipment.
  -SUBJECT;     ELECTRICAL DISTRIBUTION SYSTEM FUNCTIONAL INSPECTION-AT-HATCHt (50-32'1/91-202; 50-366/91'202)
Fur example: (1) existing set" points and time delay characteristics of the degraded grid undervoltage protection relays did not adequately prevent accident mitigating loads and control circuits from being operated with insufficient voltage in the unlikely event of a postulated accident, concurrent with degrbded grid Conditions; (2) a 50.59 safety analysis had not been perforhied to evaluate the effect of load additions and tap changes to the startup transformer upon the undervoltage relay set points; and (3) overcurrent fault protection relay Settings on several bus feeder breakers were not adequately coordinated with tVL fault protection on downstream.breakers to protect against a ,otentitOlTs of an entire safety bus before local downstream faults were isvlate,..,D D0C:K 0500321 GD August. 22, -1991."2 -It is our understanding that you (1) have -implemented interim administrative controls to protect the plant from unacceptably low undervoltage grid condi.--
We are forwarding the repurt of a special electrical distribution system functional inspection (EDSFI) performed June 10 through July 12, 1991, involv-ing activities authorized by Operating License Nos. DPR-57 and NPF-5 for the Hatch Nuclear Plant, Units 1 and 2. This inspeCtion was conducted by tht Special Inspection Branch of the Office of Nuclear Reactor Regulation with the
overcurrent  
:support of Region II. An exit meeting was held on July 12, 1991, during which-we discussed the team'.s findings with members of your staff.
ýrelay- settings-on -the-EDG-output breakers with downstream breakers, and (3) are in the process of evaluating-corrective actions for -under voltage, grid :proteUction and potential miscoordination of other installed ctrcuits.The inspection findings indicated that certain -activities Were apparently not conducted in full compliance with NRC requirements..
The areas examined during the inspection are discussed in the ew-closed copy of
The deficiencies described in the enclosed inspection reportwill be reviewed by the Region 11 office for any enforcement action. Any-subsequent actions will be taken by Region It.In accordance with 10 CFR 2.790 of the Commnision's regulations, a copy (f this letter and its enclosures will be placed in the NRC Public Document Room.ino tisn~ ispreiquffed to -thls leTWer.ing th-is irspection, we will be pleased Should you have-any questfdhs concern-to discuss them with you.Sincerely, (ORIGINAL SICNMf BY SL'9VEN.A.
  ýour inspection report; The inspection team assessed the desigr,, design imple-mentation and technical support of the electrical distributiun Systen (EDS).
VA1RGA):Steven A. Varga, Director Division of Reactor Proýjects, I/Il-Office of Nuclear Reactor .Regulation.
The inspection consisted of a selective review of EDS design calculations, relevant procedures, representative records, installed equipment and interview-with engineering and technical support staff.
    -hE design and design implementation of the EDS at Hatch were generally accept-able. Several strengths were identified in the areas of retrievability of documents, monitoring of grid stability, self-assessment, and competence of the
    )technical support staff. However, some deficiencies were identified including
    *inadequate unider voltage protection for plant operation under degraded grid voltage conditions and inadequate coordination of short circuit/fault protec-
:tiov devices for safety-related equipment. Fur example: (1) existing set" points and time delay characteristics of the degraded grid undervoltage protection relays did not adequately prevent accident mitigating loads and control circuits from being operated with insufficient voltage in the unlikely event of a postulated accident, concurrent with degrbded grid Conditions; (2) a 50.59 safety analysis had not been perforhied to evaluate the effect of load additions and tap changes to the startup transformer upon the undervoltage relay set points; and (3) overcurrent fault protection relay Settings on several bus feeder breakers were not adequately coordinated with tVL fault protection on downstream.breakers to protect against a ,otentitOlTs of an entire safety bus before local downstream faults were isvlate,.
      .,D D0C:K 0500321 GD
 
August. 22, -1991
                                              ."2 -
It is our understanding that you (1) have -implemented interim administrative controls to protect the plant from unacceptably low undervoltage grid condi.
  --tions,;-*(.2--have--Coordinated-ihe overcurrent ýrelay- settings- on -the-EDG-output breakers with downstream breakers, and (3) are in the process of evaluating
  -corrective actions for -under voltage, grid :proteUction and potential miscoordination of other installed ctrcuits.
The inspection findings indicated that certain -activities Were apparently not conducted in full compliance with NRC requirements.. The deficiencies described in the enclosed inspection reportwill be reviewed by the Region 11 office for any enforcement action. Any-subsequent actions will be taken by Region It.
In accordance with 10 CFR 2.790 of the Commnision's regulations, a copy (f this letter and its enclosures will be placed in the NRC Public Document Room.
ino   tisn~ ispreiquffed to -thls leTWer.         Should you have-any questfdhs concern-ing th-is irspection, we will be pleased to discuss them with you.
Sincerely, (ORIGINAL SICNMf BY SL'9VEN.A. VA1RGA)
:Steven A. Varga, Director Division of Reactor Proýjects, I/Il-Office of Nuclear Reactor .Regulation


==Enclosure:==
==Enclosure:==


InspectionReport 50'-321/91-202 and 50-366/91402 R4:f1 111 11 ASata~f PJFi-l1io~n LDWer~t 0840u/91 08/;? 1 91. 081 _4.-C:RSIB:DR1.
InspectionReport 50'-321/91-202 and 50-366/91402 R4:f1               111           11               RSIB;DRIS      fSB      I ASata~f       PJFi-l1io~n   LDWer~t           SSandersl    )U,'~N~rr~
C"RSI B.:DR. S OIWIS : NRRý50P11orkin -EVIntro 9KGrimes-08/1..V91 08 /0-W 9 1 0,,91 RSIB;DRIS fSB I SSandersl )U,'~N~rr~
0840u/91             08/;? 1 91. 081 _              08/,1/91        0'8/'-V.91.
08/,1/91 0'8/'-V.91.
4.-C:RSIB:DR1.       C"RSI B.:DR. S OIWIS :NRR
t.-. W. G. Hairston, I...Georg Power: LCompany cc.:Mr. Ernest L.I Blake,. Jr,.."Shaw, Pittman, Potts and Trowbridgt
ý50P11orkin           -EVIntro         9KGrimes
ý2300l-" S-t-et. i N.W.. -- ` _-;.-Washington, D.C. 20037;it, J.: T. Beckham',Vice Presidwjit  
  -08/1..V91         08/0-W 91      0,,91
-Plant. Hatch Georgia Power Company P.O. Box 1295.Bi.rminghaw., Alabama 352C.I:Mr. S. J. Bethay ,Manager Licensing  
 
-Hatch Georgia: Power Company P.O. Box '12.9 .Birmingham, Alabama 352N iMr. L, Siililner-Ge;ira-l Manager, NuclearPlant Ruute 1, Bux 439 B).Iley ,..Georg ic ' 31513 R.sident ,nspector U.-S. NuclearReguladtory Conmi.iss.ian.
t.-. W.G. Hairston, I...             - 3  -          Edwin 1. Hatrh Nuclear Plant, Georg     Power: LCompany                             .Units Nos...1aInd.2 cc.
Route 1, Box-7 2. --TBaxley, Geurgid. 31513, Adihnistrttor, Regior. 1I U.S '-. .Nuclear Regulatory Commissionr 101. Marietta 'Street, Suite 2900-Atlanta, Georgia 30323 hr. J. Le.onard Ledbetter, Director Environintntal Protection Division DepartmenL uf Niatural Resources.205:Butler Street, S.E., Suite 1252 Atlanta, Georgia. 30334-3 -Edwin 1. Hatrh Nuclear Plant,.Units Nos...1aInd.2 Mr. R. P. McDonald Executive Vice President
:Mr. Ernest L.I Blake,. Jr,..                         Mr. R. P. McDonald "Shaw, Pittman, Potts and Trowbridgt               Executive Vice President -
-
ý2300l-" S-t-et. i     N.W..   -- _- `              .Nuc*lear Operations
Operations Georgia Power Company' P.O. Box 1295 Birmingham.
;.-Washington, D.C.         20037                     Georgia Power Company
Alabama 35201 Mr. Alan R. Herdt, Chief Project Branch 03 U.S. Nuclear Regulatory Commission 161 Marivtta Street, NW,:Suite 2900 Atlanta, Georgia 30323 Mr. Dan Smith-PIrogram Director.
                                              '      P.O. Box 1295
of Power Produc'tion Oglethorpe Power Corporation 100 Crescent.Centre Tucker,(Georgia 30085 Charles A. Patr.zia, Esq.Paul,. Hastings,ý J-rnosky..&
  ;it, J.: T. Beckham                                 Birmingham. Alabama 35201
Walker 12th Floor.1050 Connectict "Avenue, N.W. W"-Washin'gton, DC. "20036 -. .S" Mr. Charles H. Wadger-Office of Planning and-Budget Room 610.270 Washington Street,:S.W.
  ',Vice Presidwjit - Plant. Hatch Georgia Power Company                               Mr. Alan R. Herdt, Chief P.O. Box 1295                                       Project Branch 03
Atlanta, Georgia 30334 Chairman Applirg County- Coiunis5ions County Courthouse Baxley, Georg'ia 31513 U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR~ REACTOR REGULATION Division~
  .Bi.rminghaw., Alabama 352C.I                       U.S. Nuclear Regulatory Commission 161 Marivtta Street, NW,:Suite 2900
of Reactor InspeLtiou1 and Safeguords NRC Insptctitun Rtpo 1 rt-. 50-321191-f"O0 anid 50-366j91-2CS':
:Mr. S. J. Bethay                                     Atlanta, Georgia 30323
Uu.cr.ket Nos; 5C-31'61 iand 50-3bC LictioseE:
,Manager Licensing - Hatch Georgia: Power Company                             Mr. Dan Smith P.O. Box '12.9       .                             -PIrogram Director. of Birmingham, Alabama 352N                               Power Produc'tion iMr. L, Siililner-                               Oglethorpe Power Corporation 100 Crescent.Centre Ge;ira-l Manager, NuclearPlant                     Tucker,(Georgia 30085 Ruute 1, Bux 439 B).Iley ,..Georg ic ' 31513                         Charles A. Patr.zia, Esq.
Georgio Puwe-r Compnpiry Pficility Nai*;e filtch Nuckar Plant Ui~ts 1 and 2 Inspectiurs Conducted:
Paul,. Hastings,ý J-rnosky..& Walker R.sident ,nspector                                 12th Floor.
Junte 10 through July 12, 1991 Licer~se No.: DPR-57 and NPF-5 Irispectiun Teamh: A. S. Gautam, Team Leader, NRR P. Fillicn, Reactor Inspect.r, Region 11 L. Wert, SRI Hatch, Region II S. Sanders, Mechar,ical Engineer, NRR L. Tran, Electrical Engineer, NPR NPC Prepared by: Reviewed by: Apprtuved by: p;.P.L.Leung, Atumic Energy Canada Ltd (A'LCL)Lyles, AECL Maggio, Engineering Planning v~d Mar~agemien Guntt~tr, Brookhaven Ldbs Wc'.g, Broukriaw~ri Labs AnimI 5. autal,, Team Leader T1eaiL. illspectior Section A Special Inspectih, Branch of Reactor Irspection and Safeguards Office of Nuclear Redctor Regulation Do7a6d Norkin, Chief TIeti inspection Section A Special Inspectiun Branch Division of Rtactor Inspection arid Safeguards Office of Nuclear Reactor RegulQtion Eugene i.ru, Chief Special. 1nspection Branch Division of Reactor Inspection and Safeguards Offict; of tuclear Reactor Regulotiun
U.-S. NuclearReguladtory Conmi.iss.ian.            1050 Connectict
~t (EPP)ffat e 9109040298 91092 PDA ADOCI @P0O I 0D LxECUTIVE  
                                                    "-Washin'gton,  DC. "Avenue, "20036  N.W.
                                                                                  -. W .
Route 1, Box-7 2. --
TBaxley, Geurgid. 31513,
*Regional Adihnistrttor, Regior. 1I         S"      Mr. Charles H. Wadger U.S'-. .Nuclear Regulatory Commissionr         -  Office of Planning and-Budget 101. Marietta 'Street, Suite 2900-                 Room 610 Atlanta, Georgia 30323                             .270 Washington Street,:S.W.
Atlanta, Georgia 30334 hr. J. Le.onard Ledbetter, Director                 Chairman Environintntal Protection Division                 Applirg County- Coiunis5ions DepartmenL uf Niatural Resources                   County Courthouse
.205:Butler Street, S.E., Suite 1252                 Baxley, Georg'ia 31513 Atlanta, Georgia. 30334
 
U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR~ REACTOR REGULATION Division~ of Reactor InspeLtiou1 and Safeguords NRC Insptctitun Rtpo1rt-. 50-321191-f"O0                       Licer~se No.: DPR-57 and anid 50-366j91-2CS':                             NPF-5 Uu.cr.ket Nos;   5C-31'61 iand 50-3bC LictioseE:     Georgio Puwe-r Compnpiry Pficility Nai*;e     filtch Nuckar Plant Ui~ts 1 and 2 Inspectiurs Conducted:         Junte 10 through July 12, 1991 Irispectiun Teamh:       A. S. Gautam, Team Leader, NRR P. Fillicn, Reactor Inspect.r, Region 11 L. Wert, SRI Hatch, Region II S. Sanders, Mechar,ical Engineer, NRR L. Tran, Electrical Engineer, NPR NPC Cw*,sult=r*ts          p;. Leung, Atumic Energy Canada Ltd (A'LCL)
Lyles, AECL P. Maggio, Engineering Planning v~d Mar~agemien ~t  (EPP)
L. Guntt~tr, Brookhaven Ldbs Wc'.g, Broukriaw~ri Labs Prepared by:
AnimI 5.     autal,, Team Leader T1eaiL. illspectior Section A Special Inspectih, Branch Division* of Reactor Irspection and Safeguards Office of Nuclear Redctor Regulation Reviewed by:
Do7a6d Norkin, Chief                                     ffat e TIeti inspection Section A Special Inspectiun Branch Division of Rtactor Inspection arid Safeguards Office of Nuclear Reactor RegulQtion Apprtuved by:
Eugene     i.ru, Chief Special. 1nspection Branch Division of Reactor Inspection and Safeguards Offict; of tuclear Reactor Regulotiun 9109040298 91092 PDA ADOCI @P0O I 0D
 
LxECUTIVE  


==SUMMARY==
==SUMMARY==
A Nuclear Regulator2y Cowmilssi
 
: r. 1., tean. conducted ai, tlectrical distributhi...
A Nuclear Regulator2y Cowmilssi r. 1
system functiural inspection
                                        .,  tean. conducted ai, tlectrical    distributhi...
' I ', at tht Hatch hucl]ar Plunt Units I and 2.The inspection was conducted
system functiural inspection ' ', I at tht Hatch hucl]ar Plunt Units I and 2.
: b. e Special IIispection eraoich of the Office. of Nucledr Reactor Regulatiuo (NPRI:i from June 10 through July 1', 1991.Thv NRC inspectiun team reviewed the desi gn ana desigli implerietatiort of the plart electrical distributioti system (EDS) irnd the adequacy of assucibted ergineerirg bnd technical support. To accomplish this, the team reviewed the design and installation of electrical and mechanical tDS equipment, reviewed.test programs and prucedures affecting the EDS, and interviewed appropriate corporate and site personnil, A number of strengths were Identifiled as wtll as several deficiencies.
The inspection was conducted b.          e Special IIispection eraoich of the Office. of Nucledr Reactor Regulatiuo    (NPRI:i from June 10 through July 1', 1991.
For the sam:ple selcted, the desigy, and i0stdllatiOn of the EDS at the Hatch Nuclear Plant was generally acceptable.
Thv NRC inspectiun team reviewed the desi gn ana desigli implerietatiort of the plart electrical distributioti system (EDS) irnd the adequacy of assucibted ergineerirg bnd technical support. To accomplish this, the team reviewed the design and installation of electrical and mechanical tDS equipment, reviewed.
Engir,eering calculations and other desigr documentation for attributes of the EDS were retrievable and verifiable.
test programs and prucedures affecting the EDS, and interviewed appropriate corporate and site personnil,      A number of strengths were Identifiled as wtll as several deficiencies.
This was a strength compared to other plants of the same vintage. In most cases, enginvering calculations had assumptiors and cOnClusions that were technically sound. Analyses for bus tronsfers were generally compreht.nsive.
For the sam:ple selcted, the desigy, and i0stdllatiOn of the EDS at the Hatch Nuclear Plant was generally acceptable. Engir,eering calculations and other desigr documentation for attributes of the EDS were retrievable and verifiable.
Ilechanical systems were well designed to support the EDS. There was ar, eftec-tive test prograim for relays ard breaker&;
This was a strength compared to other plants of the same vintage.              In most cases, enginvering calculations had assumptiors and cOnClusions that were technically sound. Analyses for bus tronsfers were generally compreht.nsive.
the program included testing beyond the requirements
Ilechanical systems were well designed to support the EDS.            There was ar, eftec-tive test prograim for relays ard breaker&; the program included testing beyond the requirements of the technical specifications.          There was an aggressive program for the configuration control of fuses. Key staff support from various departments was sufficient in number and the engineers were knuwledgeab.


==REFERENCES:==
==REFERENCES:==
: 1. GPC Voltage Study 91212PG, 1991*2. Letter from R.J. Kelly to USNRC 'Office of Nuclear Reactor Regulation, dated December 7. 19S and under NRC Dockets 50-321, and 50-366.., :GPC letter from W.A. Widner to USNRC Office of Nuclear Reactor Regulation OResporse to Request for Additional Infornation--System Voltage Study," dated October 9, 1980 and Voltage Study Calculation,.
: 1. GPC Voltage Study 91212PG, 1991
Rev. 2, (April 1980.)I A-3 DEFICIVIICY 91-202-03;-INDING TITLE: fast Transfer Permissive Relay (Section.2.2., of report)DESCRIPTION-OF CONDITION:
*2. Letter from R.J. Kelly to USNRC 'Office of Nuclear Reactor Regulation, dated December 7. 19S and under NRC Dockets 50-321, and 50-366.
During undervoltagc conditions the logic for the 4160-Volt .bses tr~nsferred.the e-ssertia]
  ., :GPC letter from W.A. Widner to USNRC Office of Nuclear Reactor Regulation OResporse to Request for Additional Infornation--System Voltage Study,"
buses from SAT 10 to SAT IC. -the voltage un 4160-Volt buses remained inadequate for one secoWd the logic, would transfer the buses from IC-tu the EDGs. Previously d set of CV-7 permissive relays sensed undeevoltage un the SAT IC and transferred power from IC to the EOGs. These permissive relays, as described in Table 3.2013 of Hatch Ulilt 1 technical specifications (TS) were required to be"lnstantaneuus" when transferring tht bus from the offsite (SAT)to onsite (EDG) suurce. However, this relay hiad a "time delay" feature in cunflict with the TS.:The team noted that i.n April .19&1 a failure of these CV-7 permissive rtlays*durillg testing had resultea in a failure of the EDGs to energize the safety.busts. After an LLR was -submitted, discussions were held between HNR and a.lodification was proposed to alter the function of these two relays. In ithe interim, -Table 3.2-1-3 was added to the 7S (May 6, 1982, TS Amendments 88 and 27 voert approved which included Table 3.2-13 and the degraded grid and -undervoltage requiremnents).
dated October 9, 1980 and Voltage Study Calculation,. Rev. 2, (April 1980.)I A-3
Thy nodification (DCR 82-34). was completed in 1983. The licensee stated-that these relays no lcngier transferred tht4160-Volt bus from'the offsite (SAT) to onsite (EDG) power. These relays had been modified to only sensa undervoltage on-the SAT IC and.control its.associated breaker. -.The.transfer .function-was-currently performed by another set of relays on the.4160-volt buses that -would- not be affected by the pernissive relays. .The tean-had.iio safety. concerns regarding the function 'Of the CV-.7 relay, howevee, the .TS.-did"not reflect .the actual. piant.configurationri.-.REQUIRI4.ENTS:
 
Technical Specificatlors-Table 3.2-13, Hatch Unit 1.REFEREINCES:
DEFICIVIICY 91-202-03
;-INDING TITLE:     fast Transfer Permissive Relay (Section.2.2.,     of report)
DESCRIPTION-OF CONDITION:
During undervoltagc conditions the logic for the 4160-Volt .bses tr~nsferred
.the e-ssertia] buses from SAT 10 to SAT IC. -       the voltage un 4160-Volt buses remained inadequate for one secoWd the logic, would transfer the buses from IC
-tu the EDGs. Previously d set of CV-7 permissive relays sensed undeevoltage un the SAT IC and transferred power from IC to the EOGs. These permissive relays, as described in Table 3.2013 of Hatch Ulilt 1 technical specifications (TS) were required to be"lnstantaneuus" when transferring tht bus from the offsite (SAT) to onsite (EDG) suurce. However, this relay hiad a "time delay" feature in cunflict with the TS.
:The team noted that i.n April .19&1 a failure of these CV-7 permissive rtlays
*durillg testing had resultea in a failure of the EDGs to energize the safety
.busts. After an LLR was -submitted, discussions were held between HNR and a
  .lodification was proposed to alter the function of these two relays.       In ithe interim, -Table 3.2-1-3 was added to the 7S (May 6, 1982, TS Amendments 88 and 27 voert approved which included Table 3.2-13 and the degraded grid and -undervoltage requiremnents). Thy nodification (DCR 82-34). was completed in 1983. The licensee stated-that these relays no lcngier transferred tht4160-Volt bus from' the offsite (SAT) to onsite (EDG) power. These relays had been modified to only sensa undervoltage on-the SAT IC and.control its.associated breaker. -.The.
transfer .function-was-currently performed by another set of relays on the
.4160-volt buses that -would- not be affected by the pernissive relays. . The tean-had.iio safety. concerns regarding the function 'Of the CV-.7 relay, howevee, the .TS.
-did"not reflect .the actual. piant.configurationri.-
  .REQUIRI4.ENTS:
Technical Specificatlors- Table 3.2-13, Hatch Unit 1.
REFEREINCES:
: 1. Table 3.2-13 of Hatch Unit 1 Technical Specification.
: 1. Table 3.2-13 of Hatch Unit 1 Technical Specification.
: 2. Relay Lat; Sheet 40cof UW-17, Plant HMtch.A-4 DEFICIENCY 91-202-04:
: 2. Relay Lat; Sheet 40cof UW-17, Plant HMtch.
FINDING 11TLE:: EDG Remote Shutdown Prucedure (Section Z..2.2 of Report)DESCRIPTION OF CONDITION:
A-4
The EOG kteptt Shutdown Procedure, Document Number 31RS-OPS-002-2S for EDGs IB (Swing)., ZA, and 2C, incorr.ectly assumed diesel generator loads to be runnln9 at 0.8 power fe(tor when in fact these loads ran at 0.9 power fdctor. In the procedure, on Itages 2, 5, 9 and 13,'a "CAUTION" to the operator stdtLed that the diesel generators must not exceea the ratings of 490 amps continuous and 660 amps for 7-day/168 hour rating. Based on a 0.9 power factor, these current ratings allowed the diesel generators to exteed the maximum kilowatt rating.At 490 amps, the diesel generators operated at 3174kWs (continuous), which exceeded tht ZB50-kW maximum rating. At 560 amps, the diesel generotors operated et 3,627KI (7 day/.168-huuri which exceeded the 3250kWs maximunm rating.Siric the available instruewrtation only mon itured current, if the procedure.
 
had bf-n isplement~ed tht Wfis--,coakl have been run-"at an ou-tpiit higher than the Maximo diese .generator ratinq. To coerect this error, the licensee agreed to re'vise..the procedure-to reflect lower current ratings based on a 0.9 power factor, sto as tQ assure the die.sel generators were operated within their continuous and 7-day ratings..10 FR-Part 5,Appevnd iY E, ZCrite'rfor,.'I I I, Doeign Control,.
DEFICIENCY 91-202-04:
requirts measures to bees.tablished to eilsure tht deslgnb.asis.is correctly translated into specifi-c'tion- drawigs, pricedures, and instructiorS.
FINDING 11TLE::   EDG Remote Shutdown Prucedure (Section Z..2.2 of Report)
DESCRIPTION OF CONDITION:
The EOG kteptt Shutdown Procedure, Document Number 31RS-OPS-002-2S for EDGs IB (Swing)., ZA, and 2C, incorr.ectly assumed diesel generator loads to be runnln9 at 0.8 power fe(tor when in fact these loads ran at 0.9 power fdctor.         In the procedure, on Itages 2, 5, 9 and 13,'a "CAUTION" to the operator stdtLed that the diesel generators must not exceea the ratings of 490 amps continuous and 660 amps for 7-day/168 hour rating. Based on a 0.9 power factor, these current ratings allowed the diesel generators to exteed the maximum kilowatt rating.
At 490 amps, the diesel generators operated at 3174kWs (continuous), which exceeded tht ZB50-kW maximum rating. At 560 amps, the diesel generotors operated et 3,627KI (7 day/.168-huuri which exceeded the 3250kWs maximunm rating.
Siric the available instruewrtation only mon itured current, if the procedure.
had bf-n isplement~ed tht Wfis--,coakl have been run-"at an ou-tpiit higher than the Maximo diese .generator ratinq. To coerect this error, the licensee agreed to re'vise..the procedure-to reflect lower current ratings based on a 0.9 power factor, sto as tQ assure the die.sel generators were operated within their continuous and 7-day ratings.
.10 FR-Part 5,Appevnd iY E, ZCrite'rfor,.'I I I, Doeign Control,. requirts measures to bees.tablished to eilsure tht deslgnb.asis.is correctly translated into specifi-c'tion- drawigs, pricedures, and instructiorS.
I($REV4NCE:
I($REV4NCE:
: 1. Electrical Restoration Remote Shutdown Procedure, Document Number*3$-0PS- 2-2S,' Revision 0, Dated Jaouary 12., 1991.
: 1. Electrical Restoration Remote Shutdown Procedure, Document Number
UNRESOLVED ITEM 91-202-05 FINVINC TITLE: Siling of-2S0. .Vdc/600-Vc Inverter&
      *3$-0PS-   2-2S,' Revision 0, Dated Jaouary 12., 1991.
(.Secttor 2.4 uf report)DESCRIPTIO1 OF CONDITTION:
 
The- teami-revitwed the capacity of the 60.-volIt iniverter R44-S002 .providing power to four MOVs in lDivision 1, and Inverter R44-S003, providing power to fiv* MOVs in Division 2. During an accident each inverter load included operation of the RHR injection, minimunt flow, and recirculat~ing pump suction valves. Under postulated wurst-case conditions each inverter would be required to supply power simultaneously to close the recirculating discourage valve B31-FO31A and the RHR minimumi flow valve El.14FO7A..
UNRESOLVED ITEM 91-202-05 FINVINC TITLE:     Siling of-2S0. .Vdc/600-Vc Inverter& (.Secttor 2.4 uf report)
and to stroke the RHR irjection valvt E1.1-FO14A.
DESCRIPTIO1 OF CONDITTION:
The team was concerned that the inverturs -may not have 'adequate capacity to provide enough power to stroke the valvt.s within tht.time requtrcd by the technical specifications.
The- teami-revitwed the capacity of the 60.-volIt iniverter R44-S002 . providing power to four MOVs in lDivision 1, and Inverter R44-S003, providing power to fiv* MOVs in Division 2. During an accident each inverter load included operation of the RHR injection, minimunt flow, and recirculat~ing pump suction valves. Under postulated wurst-case conditions each inverter would be required to supply power simultaneously to close the recirculating discourage valve B31-FO31A and the RHR minimumi flow valve El.14FO7A.. and to stroke the RHR irjection valvt E1.1-FO14A. The team was concerned that the inverturs -may not have 'adequate capacity to provide enough power to stroke the valvt.s within tht
The lnverters were load tested every 18 months to verify their capabil.ity to stroke the r tqu~reo NGVs., Procedure 345V-R44-O01-1S "LPC; Iriverters Load Teitifng required inv'er-tvr R44-5003 10u simu~taousl stro6ke four' valvet ariýd inverter A44-SO02 to Simultaneously stroke three valves. However, the test procedure did riot measure the strokt of the valves to ensure that the stroke time was within, the requirenaents of the techrical.
.time requtrcd by the technical specifications.
specifications.
The lnverters were load tested every 18 months to verify their capabil.ity to stroke the r     tqu~reo NGVs., Procedure 345V-R44-O01-1S "LPC; Iriverters Load Teitifng required inv'er-tvr R44-5003 10u simu~taousl stro6ke four' valvet ariýd inverter A44-SO02 to Simultaneously stroke three valves. However, the test procedure did riot measure the strokt *ime of the valves to ensure that the stroke time was within, the requirenaents of the techrical. specifications.
The licursee agreed to perform ar appropriate LPCI inverter load test during the next refueling outage to verify stroke't-i,.
The licursee agreed to perform ar appropriate LPCI inverter load test during the next refueling outage to verify stroke't-i,.
I.11 of 10 Cfr Part 50,. Appendix E., st."t#s that- design control measures shall prmiidt for verifying the adequacy0 of design. such bs by the ptrfoemance of design. reviews, by the use of alternateor"simplifJed..calculational methods,the performance of a suitable testing program.REFERE CE: 1. LPCI !rmv:rters Load Testing Procedure.
Cri*terion. I.11 of 10 Cfr Part 50,. Appendix E., st."t#s that- design control measures shall prmiidt for verifying the adequacy0of design. such bs by the ptrfoemance of design. reviews, by the use of alternateor"simplifJed..calculational methods, or.*t the performance of a suitable testing program.
34SV-P44-O01,1S.
REFERE CE:
I C I *IEcY 91-240246 FINDING 'TITLE: Incorrect Coordisrtion of the EDG Circuft-Breakers (Section 2.5.1 of report)DESCRIPTiON OF CONDITION:
: 1. LPCI !rmv:rters Load Testing Procedure. 34SV-P44-O01,1S.
The fault current relay protection on the five EDG output circuit breakers were not coordinated with the relays on the downstream breakers.
 
For example voltage restraint overcurrent rel ay IJCV51 was incorrectly coordinated with the emergency 416G-Vult bus bratich feeder circuit breaker protective relay CO-5.During a loss of offsite power with the COG Supplying power to the emergency 4160-volt bus, postulated faults, such as a high-impedance fault on a branch feeder, a sluggish motor start with an extended current draw near lucked rotor current, or a continuous lockied rutor condition, could cause loss of the associ-ated 4160-volt bus. The licer.see analyzed this conditfon, determined new settings for the IJCV51 relays on theL EDG output breakers, and reset these relays duilng the insptctivn.
ICI *IEcY 91-240246 FINDING 'TITLE:   Incorrect Coordisrtion of the EDG Circuft-Breakers (Section 2.5.1 of report)
".Tbe lfcensee did rOt recognize the EDG circuit breaker eoordination error when -reviewing the."Plant HatchrRelaying Data Uocunmenit" during the Appemdix R fire protectior; study.REQUIREMENTS:
DESCRIPTiON OF CONDITION:
ýCriteriun III of 10 CFR Part 60, Appenrdix B, states that dtsign.control measures.,shall priuvide for.verifying the adequacy of design, such a-s by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performanct-of a suitable testing program.REF ERENCES".1. "Plant Hatch. Relayring.
The fault current relay protection on the five EDG output circuit breakers were not coordinated with the relays on the downstream breakers. For example voltage restraint overcurrent rel ay IJCV51 was incorrectly coordinated with the emergency 416G-Vult bus bratich feeder circuit breaker protective relay CO-5.
Data .Document" (also referred to as "Units I and 2 Appendix R Protective Device Coordination Study .- Off-site Source to Largest 600V"Luods");
During a loss of offsite power with the COG Supplying power to the emergency 4160-volt bus, postulated faults, such as a high-impedance fault on a branch feeder, a sluggish motor start with an extended current draw near lucked rotor current, or a continuous lockied rutor condition, could cause loss of the associ-ated 4160-volt bus. The licer.see analyzed this conditfon, determined new settings for the IJCV51 relays on theL EDG output breakers, and reset these relays duilng the insptctivn.
transmitted under cover letter dated September  
".Tbe lfcensee did rOt recognize the EDG circuit breaker eoordination error when     -
!3, 1985.2. Diesel- GerieratorOynaihic Loading C.dlculation 552347 (Colt/Fairbanks FMorse Engineering Report MSS99511148901R, dated hovember 14, 1989).A-7 DEFICIENCY 91-202-07'FINDING TITLE: Coordination Of 1'20-.Vcand 12-Vdc Circuits (Section 2.5.2 of report)DESCRIPTION OF CONDITION:
reviewing the."Plant HatchrRelaying Data Uocunmenit" during the Appemdix R fire protectior; study.
The team roted various deficiencies in the courdination calculatiuns.
REQUIREMENTS:
Generic-fuse coordination studies specified approved configurations for various design.Lunditions.
ýCriteriun III of 10 CFR Part 60, Appenrdix B, states that dtsign.control measures
Calculatiun Number 87 Elect (Bechtel), Revision 3, dated January 8, 1990 had several incorrect coordinations for specific ranges of fault current between upstream, breakers -arid downstream fuses for 120 Vdc arid 125 Vdc control circuits.Time current curve sheet DB1, Revision 1 showed that upstream breaker Gould E41 20A had been incorrectly coordinated with Bussmnai fuse Fil4 ISA for a fault current range of over 40 amperes. The calculation showed incorrect coordination on time current curve sheets D82 for a 1fault of approximately 400 anfperes, D83 for a fault over 400 amperes, D85 for a fault ever 400 amperes, and D90 for 'a fault of 600 amperes.The team roted that this calculation was used. in the fuse upgrade and replace-ment program, and concluded that these "approved breaker/fuse configuratlcns'lhave resulted in incorrect coordinotion.
.,shall priuvide for.verifying the adequacy of design, such a-s by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performanct-of a suitable testing program.
Approximately 6000 fuses includ-ing a1lcontrol room fuses, .had already, been reviewed i.n this program for 12 0-Vac arid 12M-Vdc circulits in Units 1 and. 2. Although the-. licensee was of the opinion. that. the suspect combinations had never -had been uscd the. licrrs.ee.greed to review the generic fuse doordin~twri stodies. and installations for incorrect coordination of breaker/fuse configuratidonsý..REQUIREM4ENLT  
REF ERENCES".
-.10 CFR Part 50, Appendix B. Criterion 111, Design Control, requires design contrul nPeasures to be provided for verifying the adequacy of design by per-forming design reviews, using, alternate or..Simplified calculational methods, or providing a suitabTe testing prugram.
: 1.   "Plant Hatch. Relayring. Data .Document" (also referred to as "Units I and 2 Appendix R Protective Device Coordination Study .- Off-site Source to Largest 600V"Luods"); transmitted under cover letter dated September !3, 1985.
: 1. Calculation titled, "Breaker/Fuse, Fuse/Fuse.Coordinatiun and Cable Auto-lgtioiun Curves for Fuse/Cable Combination for 120Vac Ind l25Vdc system,"
: 2. Diesel- GerieratorOynaihic Loading C.dlculation 552347 (Colt/Fairbanks FMorse Engineering Report MSS99511148901R, dated hovember 14, 1989).
87 Elect (Bechtel), Revision 3, dated'January 8,.1990.A4B OBSERVATION 91-202-08.T41.DING TITLE: Discrepancies filCoordination Calculations (Sectioni 2.5.3 of report)DESCRIPTION OF CONDITION:
A-7
VUrious discrepancies were noted in coordination calculations f6r the EOS*equipnient making it very difficult for the team to determine if the protection on the feeder breakers to essential buses was coordinated with the protection or, downstream breakers.
 
This was because the coordination study was fragmented.
DEFICIENCY 91-202-07
For example,.
'FINDING TITLE:     Coordination Of 1'20-.Vcand 12-Vdc Circuits (Section 2.5.2 of report)
calculations SEN-89-010 and SEII-89-008 for specific overcurrent trip device modifications had nut been integrated With other calculations..Also, Appendix R calculations only addressed Appendix P. buses, and loads and were not integrated with other calculations.
DESCRIPTION OF CONDITION:
The team Concluded that this approach of satisfyIng coordination for a -specific modification could cause inadvertent errors in coordination.
The team roted various deficiencies in the courdination calculatiuns. Generic
There were instances of missing design input, guidelines, references, and 4ssumtpij.4.-.  
-fuse coordination studies specified approved configurations for various design
-Far..exampole- -results froam .short -ciruit calculation had been .used without the calculatiton being identified and various curves and calcula-tion sheets were not indexed, Making it difficult to determine if any sheets were mi.ssing.
.Lunditions.
In addition, although.a design guideline of Z,400 amperes had been establisthed as the maximun, settirg on 600-volt instantaneous or short time t'rip devices, this guideline was not addressed in calculations, Protetiv e device .tine curet ,typicaI...
Calculatiun Number 87 Elect (Bechtel), Revision 3, dated January 8, 1990 had several incorrect coordinations for specific ranges of fault current between upstream, breakers -arid downstream fuses for 120 Vdc arid 125 Vdc control circuits.
curves .were used for 'mul tiple applica-tiois .However,.
Time current curve sheet DB1, Revision 1 showed that upstream breaker Gould E41 20A had been incorrectly coordinated with Bussmnai fuse Fil4 ISA for a fault current range of over 40 amperes. The calculation showed incorrect coordination on time current curve sheets D82 for a 1fault of approximately     400 anfperes, D83 for a fault over 400 amperes, D85 for a fault ever 400 amperes, and D90 for 'a fault of 600 amperes.
specific relays using-the sane typical Curve did not always have the .same -chara cter'i st ics.The title of calcu-lation number 850841)P had been changed to "Aux Sys Coordina-titon Study 4' from 'Statior, Aux System Short CircuitCalculation for Relaying and Fuse Co-orination Study'. .However, no changes had been. made to the b6dy of the.calculatiorvto transform it to a coordination Study.A-9 OEFICJEHCY 91i202-0.9
The team roted that this calculation was used. in the fuse upgrade and replace-ment program, and concluded that these "approved breaker/fuse configuratlcns'l m*y have resulted in incorrect coordinotion. Approximately 6000 fuses includ-ing a1lcontrol room fuses, .had already, been reviewed i.n this program for 120 -Vac arid 12M-Vdc circulits in Units 1 and. 2. Although the-. licensee was of the opinion. that. the suspect combinations had never -had been uscd the. licrrs.ee
ýFMIDIRG TITLE; tDiscrepanicites in'Mechanical Designi Documevitation (Sectiln 3.1.2 of repurt)ýThere weriv discrepancies iti the plant mechankial de~ign documentation.
  .greed to review the generic fuse doordin~twri stodies. and installations for incorrect coordination of breaker/fuse configuratidonsý.
Oi~ctpdncies wvre fuund between Colt Manual, SX 1314?, the FSAR, and associattd PSIC drawi~riis wtth regdrd to the ED6 air stort1ing compressor 4etpoirnts, ahd iperatlng porameters e~g., low pre~sure stdrto high presture cutriff, operating pressure aoii. the air recviver pressure relief Valve settjitog T he seismic quialifictun.
.REQUIREM4ENLT -.
documeotation -uf selected cwtporifltes ano equtfpnent in the diesel generator Suipport s~stems showed suhe discrepancies with regard to weld' lenths toi expansion tank support brackeits and diffensions.
10 CFR Part 50, Appendix B. Criterion 111, Design Control, requires design contrul nPeasures to be provided for verifying the adequacy of design by per-forming design reviews, using, alternate or..Simplified calculational methods, or providing a suitabTe testing prugram.
of supports., There were discrepancies betwemi; the 1lcensee's calculatluns for the systetr air flow distributicon, The air *CompresSor had been replaced, in. an overall lower Air teperature for tte b4ttery rcooms. However, rlcuatito-;is ha4 riat been revliq. to Show this- lower heat luad.IfVAC ,resulting~-The Tht urigindI lead antimony batttries had been repldred with lead calciuri Latteries thiat had a lOwkr hydrogen generator rate (xIO) than the ortgrinal botteritL.
REFE*RENCE:
However, the hydrogen generation rates in the calculattons had not beeri revised 't reflect tht additional margins or time it would take to reacwh dangerous or explosive Conditiour,s on loss-vcf air flow tu the. battery rooms.The P&4ariioal changes .fr Ithe Hatch Ulit 2 modification vere shown cl the plaji arrang:ement but had not the P&ID and process f luw drawings.madcf under O3C-89-356 be~n. intolrpo.oratd -into 10 CFA Part 50, Apperidix E. Crlttrion t11. Design Control, requires measures to be established to ensure the desigr basis is-correctly translated Into specifi.cation, drawings, proiu~1ures, and. instructiur,.
: 1. Calculation titled, "Breaker/Fuse, Fuse/Fuse.Coordinatiun and Cable Auto-lgtioiun Curves for Fuse/Cable Combination for 120Vac Ind l25Vdc system," CaIcuh*tion.Number 87 Elect (Bechtel), Revision 3, dated' January 8,.1990.
A-1O DEFRItEKY 914r-10~l)tL.,1f TITLE- P1.afft Serii 1CO Oter. SyritM Th,0 sIPnl U plt survice water (PSV) PIP.*%~ bNtwen t~he su pply and return~4!1*et1w v I~ves of the1i Xehergehc..
A4B
ifesul geiw~4t had a poteti t traP s;erV1cV w~ter betwretrt~h~e standby ;u dischm~e-check vov1e 2P414r321 and the dtesw1 ~enerator cou.ling wdter ou~et valve 1Ml'F414t.
 
U VA& bet heat ezihangel WAS shut down,* thk covoling fluid would be tsulated by v460 o both~ sldtisv the trappte. ceWaln fluid woud@ heat up and ~txpand, and the it~t~rol pressure would ribt, thus, ipcreaslflg Mk possibility of a ow.~Pressure C"sItioi._Owetpressuarizatlon of thot seCtion 0f the piping had 'the pOterItal to lrmpatr both, Lmop beCause MG~ 1B was shomred and could sopply either Uftit I-essentital bus 'IF o. Unfit 42 e eratial.lbus 2F. The license'&
OBSERVATION 91-202-08
cousdtted to eirnductifig a*t4684 IV# O.0-a"4 ftV1ifta.
.T41.DING TITLE:     Discrepancies filCoordination Calculations (Sectioni 2.5.3 of report)
d a 0 approipriate -stat~icm*
DESCRIPTION OF CONDITION:
opteritq -pr cedlure.This reveisior' will -require tim operators t~o maintain standby service 'water flow for , m1'owu of 112" houir aftetr the COJG was. secure* in. order to el-iminate overpressufe C~fl~re1S..M. CFO'Part 60, Appwndiy 9, trltertribj I II-, D'es'iq C ontfocl, requirits Mieasures to be estaublished to~ OBUIO,~ the design basis. fS Gurvrctly'  
VUrious discrepancies were noted in coordination calculations f6r the EOS
't ran$ la ted. 'into Wpecff-cat Wt~f Iraw.ins, 'r.dueand-insttrtiuvs..
*equipnient making it very difficult for the team to determine if the protection on the feeder breakers to essential buses was coordinated with the protection or, downstream breakers.     This was because the coordination study was fragmented.
REFEfikCES A-Il APPENDIX B*PERSCNS CONTACTED Southern Nuclear Company (SNCi/Geoiggia Power Comlpany Persotinel
For example,. calculations SEN-89-010 and SEII-89-008 for specific overcurrent trip device modifications had nut been integrated With other calculations.
'Altieer, J. N. -Project Engineer, SNC Altizer, N. -Project Engineer, SNC'Anderson, T. -Engineering Group Manager, Electrical, SHC Barker, G. Superintendent, J&C Sennett, J. 0. -Manager, Tralnling and EP*Branum, J. Project Engineer, SNC Breitenbdch, K. W. -Manager, Erngineering
.Also, Appendix R calculations only addressed Appendix P.buses, and loads and were not integrated with other calculations. The team Concluded that this approach of satisfyIng coordination for a -specific modification could cause inadvertent errors in coordination.
*Brinstr, Jr., L. -Engineerinu, Supervisor Clair, C. -Settior Engineer.
There were instances of missing design input, guidelines, references, and 4ssumtpij.4.-. - Far..exampole- -results froam . short -ciruitcalculation had been     .
SNC Curtis, S.-. Superintendenrt Operations SuppOrt.*Davis, J. D. -Plant Administratiun Manager*Davis, R, L. -Acting SAER Site Supervfsor,.SNC.
used without the calculatiton being identified and various curves and calcula-tion sheets were not indexed, Making it difficult to determine if any sheets were mi.ssing. In addition, although.a design guideline of Z,400 amperes had been establisthed as the maximun, settirg on 600-volt instantaneous or short time t'rip devices, this guideline was not addressed in calculations, Protetiv e device .tine curet ,typicaI... curves .were used for 'mul tiple applica-tiois . However,. specific relays using-the sane typical Curve did not always have the .same -chara cter'i st ics.
.*Dougherty, ii. M. -Site Representative Edge, D. L. -Manager, Nuclear Sectign Frissr, 0. M. -SAEk Site Supervisor, SNC*Furnel, P. E. Manager, Maintenathce
The title of calcu-lation     number 850841)P had been changed to "Aux Sys Coordina-titon Study4 ' from 'Statior, Aux System Short CircuitCalculation for Relaying and Fuse Co-orination Study'.     . However, no changes had been. made to the b6dy of the.
*Lewis J. -Manager, Operations
calculatiorvto transform     it to a coordination Study.
-'Garner, W. F. -Hatch Project Pranager, SNC Godby, R. K.I: Superintendent, Maintenance
A-9
.*Goode, G..A -Assistart General M6rfager Googe, M. -'Manager, Outages and PFar4dnifig.
 
*haninonds, J.- -Supervitor, Regulatory Coanplirarce
OEFICJEHCY 91i202-0.9
.*Heidt, J. 0. -Manager Engineer and L-icensing, 5NCo.Madison, 0. Engineering Vanager, SNC McGaha, ... -Design Manager, Hatch ,Robertsoh, Jr., J. W. -Acting Manager, Engineering Support Rogers, W., H.- Superintendent, Chemistry Solder, B. -Supervisor, Hatch Support,.
ýFMIDIRG TITLE; tDiscrepanicites in'Mechanical Designi Documevitation (Sectiln 3.1.2 of repurt)ý There weriv discrepancies iti the plant mechankial de~ign documentation.
SCS.*Tipps, S.'- Manager, Nuclear Safety and Complidnce Vora, A. -Engineer, Maintenance Wells, P.., Superintendent Persons. Invited by the Licensee:*Dismukes.
Oi~ctpdncies wvre fuund between Colt Manual, SX 1314?, the FSAR, and associattd PSIC drawi~riis wtth regdrd to the ED6 air stort1ing compressor 4etpoirnts, ahd iperatlng porameters e~g., low pre~sure stdrto high presture cutriff, operating pressure aoii. the air recviver pressure relief   Valve settjitog The  seismic quialifictun. documeotation -uf selected cwtporifltes ano equtfpnent in the diesel generator Suipport s~stems showed suhe discrepancies with regard to weld' lenths toi expansion tank support brackeits and diffensions. of supports.,
1I1, O.E. -Mechanical Er.9gneerw Supervisor, Bechtel*Rowe, L,. .Assistanrt Project Mdnager,.Bechtel
There were discrepancies betwemi; the 1lcensee's calculatluns for the IfVAC systetr air flow distributicon, The air CompresSor had been replaced, ,resulting~
'iWitt ,U.,o- Division Manager, CYGNA"NucearReguutoy PersonneT'*Fillion, P. -Reactor Inspector, R11'Gautam, A, S. Team Leader, NRR.* Imbro, E. V. -Chief, Special Inspection Branch, NRC/NRR*Leung, H. -Consultant
in. an overall lower Air teperature for tte b4ttery rcooms. However, -The rlcuatito-;is ha4 riat been revliq. to Show this- lower heat luad.
*Lyles, P. -Consultan:t b-1 M~a99io 'L.- 4 Consulitant-
Tht urigindI lead antimony batttries had been repldred with lead calciuri Latteries thiat had a lOwkr hydrogen generator rate (xIO) than the ortgrinal botteritL. However, the hydrogen generation rates in the calculattons had not beeri revised 't reflect tht additional margins or time it would take to reacwh dangerous or explosive Conditiour,s on loss-vcf air flow tu the. battery rooms.
*Merrschoff., E. W.. -Deputyr Director,, Rvac~tvi Projects, RTI.ErNorkfn, 0. P. -Secti~ri MO.ef PRIS, NRR.:Sanders, S-R~eictor Cngfne'tr, NRP.*Tran, L. NI. *Reai~tor Engineer, NRR*benott~s those attcwroing the ex-it irltervit.ý*
The P&4ariioal changes .fr Ithe Hatch Ulit 2 modification madcf under O3C-89-356 vere shown cl the plaji arrang:ement draw*igs but had not be~n. intolrpo.oratd -into the P&ID and process f luw drawings.
on July icj, 1911 dt the~ CIThChJsiful of the inspection.  
10 CFA Part 50, Apperidix E. Crlttrion t11. Design Control, requires measures to be established to ensure the desigr basis is-correctly translated Into specifi.
*I0% UNITED STATESNUCLEAR REGULATORY COMMISSION REGION II 101 MARIETTA STREET, NA.ATLANTA, GEORGIA 3023 October 7. 1991 Docket Nos. 50-321, 50-366 License Nos. DPR-57, NPF-5 OCT 1 4 199, Georgia Power Company ATTN: Mr. W. G. Hairston, III Senior Vice President  
cation, drawings, proiu~1ures, and. instructiur,.
-Nuclear Operations P. 0. Box 1295 Birmingham, AL 35201 Gentlemen:
A-1O
 
DEFRItEKY 914r-10~l
  )tL.,1f TITLE- P1.afft Serii 1CO Oter.SyritM sIPnl U plt survice water (PSV) PIP.*%~ bNtwen t~he su pply and return~
Th,0 4!1*et1w v I~ves of the1i Xehergehc.. ifesul geiw~4t had a poteti             t traP s;erV1cV w~ter betwretrt~h~e standby ;u dischm~e-check vov1e 2P414r321 and the dtesw1 ~enerator cou.ling wdter ou~et valve 1Ml'F414t.
U VA&bet heat ezihangel WAS shut down,* thk covoling fluid would be tsulated by v460 o both~ sldtisv the trappte. ceWaln fluid woud@ heat up and ~txpand, and the it~t~rol pressure would ribt, thus, ipcreaslflg Mk possibility of a ow.~
Pressure C"sItioi.
_Owetpressuarizatlon of thot seCtion 0f the piping had 'the pOterItal to lrmpatr both, Lmop beCause MG~ 1B was shomred and could sopply either Uftit I-essentital bus 'IFo. Unfit e eratial.lbus 2F. The license'& cousdtted to eirnductifig a 42
*t4684IV# O.0-a"4 ftV1ifta. d a0 approipriate -stat~icm*opteritq -pr cedlure.
This reveisior' will -require tim operators t~o maintain standby service 'water flow for , m1'owu of 112" houir aftetr the COJG was. secure* in. order to el-iminate overpressufe C~fl~re1S.
.M. CFO'Part 60, Appwndiy 9, trltertribj III-, D'es'iq Contfocl, requirits Mieasures to be estaublished to~ OBUIO,~ the design basis. fS Gurvrctly''tran$ la ted. 'into Wpecff-cat Wt~f Iraw.ins,                 'r.dueand-insttrtiuvs..
REFEfikCES A-Il
 
APPENDIX B
*PERSCNS CONTACTED Southern Nuclear Company (SNCi/Geoiggia Power Comlpany Persotinel
'Altieer, J. N. - Project Engineer, SNC Altizer, N. - Project Engineer, SNC
'Anderson, T. - Engineering Group Manager, Electrical, SHC Barker, G. Superintendent, J&C Sennett, J. 0. - Manager, Tralnling and EP
*Branum, J.         Project Engineer, SNC Breitenbdch, K. W. - Manager, Erngineering
*Brinstr, Jr., L. - Engineerinu, Supervisor Clair, C. - Settior Engineer. SNC Curtis, S.-. Superintendenrt Operations SuppOrt.
*Davis, J. D. - Plant Administratiun Manager
*Davis, R, L. - Acting SAER Site Supervfsor,.SNC.
.*Dougherty, ii. M. - Site Representative Edge, D. L. - Manager, Nuclear Sectign Frissr, 0. M. - SAEk Site Supervisor, SNC
*Furnel, P. E. Manager, Maintenathce
*Lewis J. - Manager, Operations
-'Garner, W. F. - Hatch Project Pranager, SNC Godby, R. K.I: Superintendent, Maintenance
.*Goode, G..A - Assistart General M6rfager Googe, M. - 'Manager, Outages and PFar4dnifig.
*haninonds, J.- - Supervitor, Regulatory Coanplirarce
.*Heidt, J. 0. - Manager Engineer and L-icensing, 5NCo
  .Madison, 0. Engineering Vanager, SNC McGaha,   ...   - Design Manager, Hatch
  ,Robertsoh, Jr., J. W. - Acting Manager, Engineering Support Rogers, W., H.- Superintendent, Chemistry Solder, B. - Supervisor, Hatch Support,. SCS.
*Tipps, S.'- Manager, Nuclear Safety and Complidnce Vora, A. - Engineer, Maintenance Wells, P.., Superintendent Persons. Invited by the Licensee:
  *Dismukes. 1I1,O.E. - Mechanical Er.9gneerw Supervisor, Bechtel
  *Rowe, L,. . Assistanrt Project Mdnager,.Bechtel
'iWitt ,U.,o- Division Manager, CYGNA "NucearReguutoy Comni*s~iqn PersonneT
'*Fillion, P. - Reactor Inspector, R11
.*'Gautam, Imbro, E.A,V. S.- Chief, Special NRR Team Leader, Inspection Branch, NRC/NRR
  *Leung, H. - Consultant
  *Lyles, P. - Consultan:t b-1
 
M~a99io 'L.- 4 Consulitant-
*Merrschoff., E. W.. -Deputyr Director,, Rvac~tvi Projects, RTI.
ErNorkfn, 0. P. - Secti~ri MO.ef PRIS, NRR
.:Sanders, S-R~eictor Cngfne'tr, NRP
.*Tran, L. NI. *Reai~tor Engineer, NRR
*benott~s those attcwroing the ex-it irltervit.ý* on July icj, 1911 dt the~ CIThChJsiful of the inspection.
 
*I0%                             UNITED STATES 0*              NUCLEAR REGULATORY COMMISSION REGION II 101 MARIETTA STREET, NA.
ATLANTA, GEORGIA 3023 October 7. 1991 Docket Nos. 50-321, 50-366 License Nos. DPR-57, NPF-5                                   OCT   14 199, Georgia Power Company ATTN: Mr. W. G. Hairston, III Senior Vice President -
Nuclear Operations P. 0. Box 1295 Birmingham, AL 35201 Gentlemen:


==SUBJECT:==
==SUBJECT:==
NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-321/91-202 AND 50-366/91-202)
NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-321/91-202 AND 50-366/91-202)
This refers to the inspection conducted by A. S. Gautam of this office on June 10 -July 12, 1991. The inspection included a review of activities authorized for your Hatch facility.
This refers to the inspection conducted by A. S. Gautam of this office on June 10 - July 12, 1991.     The inspection included a review of activities authorized for your Hatch facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the report.
At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the report.The report documenting this inspection was sent to you by letter dated August 22, 1991, Areas examined during the inspection are identifled in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice).
The report documenting this inspection was sent to you by letter dated August 22, 1991, Areas examined during the inspection are identifled in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.
We are concerned about the violation because of the examples of failure to establish appropriate design control measures.You are required to respond to this letter and should follow the instructions specified In the enclosed Notice when preparing your response.
Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice). We are concerned about the violation because of the examples of failure to establish appropriate design control measures.
In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence.
You are required to respond to this letter and should follow the instructions specified In the enclosed Notice when preparing your response.       In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NAC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NAC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be placed in the NRC Public Document Room.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be placed in the NRC Public Document Room.
Georgia Power Company 2 October 7, 1991 The responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511.Should you have any questions concerning this letter, please contact us.Sincerely,-T7 Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety  
 
Georgia Power Company                   2                       October 7, 1991 The responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511.
Should you have any questions concerning this letter, please contact us.
Sincerely,
                                                              -       T7 Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety


==Enclosure:==
==Enclosure:==


Notice of Violation cc w/encl: R. P. McDonald, Executive Vice President, Nuclear Operations Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 J. T. Beckham Vice President, Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 H. L. Sumner General Manager, Plant Hatch Route 1, Box 439 Baxley, GA 31513 S. J. Bethay Manager Licensing  
Notice of Violation cc w/encl:
-Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 Ernest L. Blake, Esquire Shaw, Pittman, Potts and Trowbrldge 2300 N Street, NW Washington, D. C. 20037 (cc w/encl cont'd -see page 3)
R. P. McDonald, Executive Vice President, Nuclear Operations Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 J. T. Beckham Vice President, Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 H. L. Sumner General Manager, Plant Hatch Route 1, Box 439 Baxley, GA 31513 S. J. Bethay Manager Licensing - Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 Ernest L. Blake, Esquire Shaw, Pittman, Potts and Trowbrldge 2300 N Street, NW Washington, D. C. 20037 (cc w/encl cont'd - see page 3)
Georgia Power Company 3 October 7, 1991 (cc w/encl cont'd)Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW Atlanta, GA 30334 Joe D. Tanner, Commissioner Department of Natural Resources 205 Butler Street, SE, Suite 1252 Atlanta, GA 30334 Thomas Hill, Manager Radioactive Materials Program Department of Natural Resources 878 Peachtree St., NE., Room 600 Atlanta, GA 30309 Chairman Appling County Commissioners County Courthouse Baxley, GA 31513 Dan Smith Program Director of Power Production Oglethorpe Power Corporation 100 Crescent Centre Tucker, GA 30085 Charles A. Patrizia, Esq.Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW Washington, D. C. 20036 ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company Hatch Docket Nos. 50-321, 50-366 License Nos. DPR-57, NPF-5 During an NRC inspection conducted on June 10 -July 12, 1991, a violation of NRC requirements was identified.
 
In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1991), the violation is listed below: 10 CFR Part 50, Appendix B, Criterion II1, requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.Contrary to the above, the following deficiencies were identified:
Georgia Power Company             3 October 7, 1991 (cc w/encl cont'd)
A b'~-.9 a.vv l 1 Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient voltage to perform their safety function (91-202-01).
Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW Atlanta, GA 30334 Joe D. Tanner, Commissioner Department of Natural Resources 205 Butler Street, SE, Suite 1252 Atlanta, GA 30334 Thomas Hill, Manager Radioactive Materials Program Department of Natural Resources 878 Peachtree St., NE., Room 600 Atlanta, GA 30309 Chairman Appling County Commissioners County Courthouse Baxley, GA 31513 Dan Smith Program Director of Power Production Oglethorpe Power Corporation 100 Crescent Centre Tucker, GA 30085 Charles A. Patrizia, Esq.
S.... b. A design review had not been performed to evaluate the impact of' -a--1-Y load additions and transformer tap changes on the undervoltage e0 A.,.o~r. protection for the electrical distribution system (91-202-02).
Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW Washington, D. C. 20036
A% C.. 9I c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
 
: d. For 120-Vac and 125-Vdc circuits, coordination calculations included several approved breaker/fuse configurations which may have resulted iA#t in incorrect coordination between upstream breakers and downstream fuses (91-202-07).
ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company                                   Docket Nos. 50-321, 50-366 Hatch                                                  License Nos. DPR-57, NPF-5 During an NRC inspection conducted on June 10 - July 12, 1991, a violation of NRC requirements was identified.       In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1991), the violation is listed below:
This is a Severity Level IV violation (Supplement 1).Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector, Hatch within 30 days of the date of the letter transmitting this Notice of Violation (Notice).
10 CFR Part 50, Appendix B, Criterion II1,   requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.
This reply should be clearly marked as a"Reply to a Notice of Violation" and should include (for each violation]:
Contrary to the above, the following deficiencies were identified:
(1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the Georgia Power Company 2 Docket Nos. 50-321, 50-366 Hatch License Nos. DPR-57, NPF-5 results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date wthen full compliance will be achieved.
A b'~-.9       a. Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient vv    l 1 voltage to perform their safety function (91-202-01).
If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.FOR THE NUCLEAR REGULATORY COMMISSION Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety Dated at Atlanta, Georgia this 7th day of October 1991 Georgia Power Company 40 Inverness Center Parkway r.'st Office Box 1295 1 Jrmihji am, Alabama 35201 Telephone 205 877-7279 J. T. Beckham, Ji.Vice President-Nuclear Hatch Project I 4 Georgia Power the southern elecirc system HL-1885 002371 November 6, 1991 U.S. Nuclear Regulatory ATTN: Document Control Washington, D.C. 20555 Commni ssIon Desk PLANT HATCH -UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION Gentlemen:
S.... **.&          b. A design review had not been performed to evaluate the impact of
In response to your letter of October 7, 1991 and in accordance with the provisions of 10 CFR 2.201, Georgia Power Company (GPC) is providing the enclosed response to the Notice of Violation associated with NRC Inspection Report 91-202. A copy of this response is being provided to NRC Region II for review. In the enclosure, a transcription of the NRC viulatlon precedes GPC's response.Should you have any questions, please contact this office.Sincerely, 3 J. TBeckham,Jr JKB/cr
                  ' -a--1-Y load additions and transformer tap changes on the undervoltage e0         A.,.o~r.           protection for the electrical distribution system (91-202-02).
: c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
: d. For 120-Vac and 125-Vdc circuits, coordination calculations included A%  C.. 9I                  several approved breaker/fuse configurations which may have resulted iA#t           in incorrect coordination between upstream breakers and downstream fuses (91-202-07).
This is a Severity Level IV violation (Supplement 1).
Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector, Hatch within 30 days of the date of the letter transmitting this Notice of Violation (Notice).       This reply should be clearly marked as a "Reply to a Notice of Violation" and should include (for each violation]:
(1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the
 
Georgia Power Company                   2         Docket Nos. 50-321, 50-366 Hatch                                             License Nos. DPR-57, NPF-5 results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date wthen full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.
FOR THE NUCLEAR REGULATORY COMMISSION Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety Dated at Atlanta, Georgia this 7th day of October 1991
 
I Georgia Power Company 40 Inverness Center Parkway r.'st Office Box 1295 1 Jrmihji am, Alabama 35201 Telephone 205 877-7279 4
J. T. Beckham, Ji.                                                   Georgia Power Vice President-Nuclear                                           the southern elecirc system Hatch Project HL-1885 002371 November 6, 1991 U.S. Nuclear Regulatory Commni ssIon ATTN: Document Control Desk Washington, D.C. 20555 PLANT HATCH - UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION Gentlemen:
In response to your letter of October 7, 1991 and in accordance with the provisions of 10 CFR 2.201, Georgia Power Company (GPC) is providing the enclosed response to the Notice of Violation associated with NRC Inspection Report 91-202. A copy of this response is being provided to NRC Region II for review.           In the enclosure, a transcription of the NRC viulatlon precedes GPC's response.
Should you have any questions, please contact this office.
Sincerely, JKB/cr 3J.TBeckham,Jr


==Enclosure:==
==Enclosure:==
Response to Notice of Violation cc: (See next page.)
Georgia Power It U.S. Nuclear Regulatory Commission November 6, 1991 Page Two cc:  Georcta Power Company Mr. H. L. Sumner, General Manager - Nuclear Plant NORMS U.S. Nuclear Regulatorv Commission. WIshington. DC.
Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Regulatory Comm-ission. Regon I I Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch 002371 700775


Response to Notice of Violation cc: (See next page.)
ENCLOSURE PLANT HATCH - UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Violation 91-202 10 CFR Part 50, Appendix B, Criterion III, requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program.
Georgia Power It U.S. Nuclear Regulatory Commission November 6, 1991 Page Two cc: Georcta Power Company Mr. H. L. Sumner, General Manager -Nuclear Plant NORMS U.S. Nuclear Regulatorv Commission.
Contrary to the above, the following deficiencies were identified:
WIshington.
DC.Mr. K. Jabbour, Licensing Project Manager -Hatch U.S. Nuclear Regulatory Comm-ission.
Regon I I Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector
-Hatch 002371 700775 ENCLOSURE PLANT HATCH -UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
50-366/91-202 Violation 91-202 10 CFR Part 50, Appendix B, Criterion III, requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program.Contrary to the above, the following deficiencies were identified:
: a. Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient voltage to perform their safety function (91-202-01).
: a. Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient voltage to perform their safety function (91-202-01).
: b. A design review had not been performed to evaluate the impact of load additions and transformer tap changes on the undervoltage protection for the electrical distribution system (91-202-02).
: b. A design review had not been performed to evaluate the impact of load additions and transformer tap changes on the undervoltage protection for the electrical distribution system (91-202-02).
: c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
: c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
: d. For 120-Vac and 125-Vdc circuits, coordination calculations included several approved breaker/fuse configurations which may have resulted in incorrect coordination between upstream breakers and downstream fuses (91-202-07).
: d. For 120-Vac and 125-Vdc circuits, coordination calculations included several approved breaker/fuse configurations which may have resulted in incorrect coordination between upstream breakers and downstream fuses (91-202-07).
This is a Severity Level IV violation (Supplement 1).RESPONSE TO VIOLATION Admission or Denial of the Violation GPC agrees that items b, c, and d stated above are valid deficiencies and occurred as described in the Notice of Violation.
This is a Severity Level IV violation (Supplement 1).
However, we believe item a does not constitute a violation.
RESPONSE TO VIOLATION Admission or Denial of the Violation GPC agrees   that items b, c, and d stated above are valid deficiencies and occurred as   described in the Notice of Violation. However, we believe item a does not   constitute a violation. The rationale for our conclusion is provided in   the response.
The rationale for our conclusion is provided in the response.We emphasize that design control measures consistent with the requirements of 10 CFR Part 50, Appendix B, Criterion III are in place to provide for verifying or checking the adequacy of design. As noted in the Inspection Report, the NRC inspection team reviewed the procedures, processes, and 002450 HL-1885 El ENCLOSURE (Continued)
We emphasize that design control measures consistent with the requirements of 10 CFR Part 50, Appendix B, Criterion III are in place to provide for verifying or checking the adequacy of design.         As noted in the Inspection Report, the NRC inspection team reviewed the procedures, processes, and 002450 HL-1885                               El
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
 
50-366/91-202 guidelines governing design control measures, plant modifications, and design calculations.
ENCLOSURE (Continued)
The inspection team concluded the following:
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 guidelines governing design control measures, plant modifications,         and design calculations. The inspection team concluded the following:
: 1. The design evaluation review and approval processes are adequate and comprehensive.
: 1. The design evaluation review and     approval processes are adequate   and comprehensive.
: 2. The engineering design and modification control processes are well proceduralized.
: 2. The engineering   design and modification   control processes are well proceduralized.
: 3. Design changes were reviewed and approved in accordance with established quality assurance/quality control controls.4. GPC's procedures controlling documentation records and modification work are generally complete and comprehensive.
: 3. Design   changes were reviewed     and approved in     accordance with established quality assurance/quality control controls.
Additionally, the NRC Inspection team indicated that Plant Hatch provides a very aggressive self-assessment effort.The four deficiencies listed as examples in the Notice of Violation are discussed below: EXAMPLE a: Example a is not considered a violation of NRC requirements.
: 4. GPC's procedures controlling documentation records       and modification work are generally complete and comprehensive.
The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter (GL) dated June 2, 1977 concerning staff positions for degraded grid protection of station electric distribution system voltages.
Additionally, the NRC Inspection team indicated that Plant Hatch provides a very aggressive self-assessment effort.
The GL addressed compliance with General Design Criterion
The four deficiencies listed     as examples in   the Notice of Violation are discussed below:
: 17. In GPC's response, a range for nominal offsite line voltages, which were evaluated and shown to adequately supply the emergency loads, was established.
EXAMPLE a:
Currently, the expected voltage range for the offsite supply is evaluated on an annual basis to include transmission system load and configuration changes since the previous study. As part of the periodic offsite source voltage study, calculations based on maximum and minimum plant and system load conditions are performed to assure acceptable voltages for emergency systems. Also, load additions to the essential buses are evaluated prior to installation under the Design Change Request (DCR) process.GPC's methodology of using minimum and maximum acceptable voltage ranges for the offsite power supply was reviewed and approved by the NRC.Specifically, GPC's system voltage study submitted to the NRC on October 9, 1980 used the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels. At that time, a minimum expected offsite source operating voltage of 98 percent of 230 kV was 002450 HL-1885 E2 ENCLOSURE (Continued)
Example a is not considered a violation of NRC requirements.
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter (GL) dated June 2, 1977 concerning staff positions for degraded grid protection of station electric distribution system voltages. The GL addressed compliance with General Design Criterion 17. In GPC's response, a range for nominal offsite line voltages, which were evaluated and shown to adequately supply the emergency loads, was established.         Currently, the expected voltage range for the offsite supply is evaluated on an annual basis to include transmission system load and configuration changes since the previous study. As part of the periodic offsite source voltage study, calculations based on maximum and minimum plant and system load conditions are performed to assure acceptable voltages for emergency systems. Also, load additions to the essential buses are evaluated prior to installation under the Design Change Request (DCR) process.
50-366/91-202 identified and established to ensure adequate bus voltages.
GPC's methodology of using minimum and maximum acceptable voltage ranges for the offsite power supply was reviewed and approved by the NRC.
To accommodate higher expected transmission system operating voltages, tap changes were made for the Station Auxiliary Transformers in 1986 and 1987. The present minimum expected offsite source operating voltage is 101.3 percent of 230 kV. Using the present minimum expected source voltage, tap connections, and load configurations, the minimum expected 1E system voltages are, generally, slightly higher than the minimum voltages submitted in 1980. Consequently, the level of undervoltage protection determined to be sufficient in 1980 has been maintained.
Specifically,     GPC's system voltage study submitted       to the NRC on October 9, 1980 used the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels. At that time, a minimum expected offsite source operating voltage of 98 percent of 230 kV was 002450 HL-1885                             E2
The existing degraded grid undervoltage relay setpoints were approved by the NRC in the Safety Evaluation Report (SER) dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
 
GPC has consistently maintained compliance with the regulatory requirements as established and approved.
ENCLOSURE (Continued)
However, GPC and the NRC staff are presently negotiating to identify a mutually acceptable method of further improving the level of degraded grid protection at Plant Hatch.EXAMPLE b: Example b is considered a violation and occurred as described in the Notice of Violation.
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 identified and established to ensure adequate bus voltages. To accommodate higher expected transmission system operating voltages, tap changes were made for the Station Auxiliary Transformers in 1986 and 1987. The present minimum expected offsite source operating voltage is 101.3 percent of 230 kV.       Using the     present   minimum expected source     voltage, tap connections,     and load configurations,   the minimum expected 1E system voltages     are, generally, slightly higher than the minimum voltages submitted in 1980.         Consequently, the level of undervoltage protection determined to be sufficient in 1980 has been maintained.
Reason for the Violation The violation was caused by the lack of a design document specifying 1E transformer tap settings.
The existing degraded grid undervoltage relay setpoints were approved by the NRC in the Safety Evaluation Report (SER)       dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection. GPC has consistently maintained compliance with the regulatory requirements as established and approved. However, GPC and the NRC staff are presently negotiating to identify a mutually acceptable method of further improving the level of degraded grid protection at Plant Hatch.
As a result, transformer tap changes were implemented using Maintenance Work Orders (MWOs) instead of the DCR process. Consequently, formal 10 CFR 50.59 safety evaluations were not performed.
EXAMPLE b:
Plant personnel and architect/engineer personnel failed to realize the tap changes represented design changes.The transformer tap changes were implemented consistent with GPC's methodology of establishing minimum and maximum ranges for offsite voltages.
Example b is considered a violation and occurred as described in the Notice of Violation.
Although formal 10 CFR 50.59 safety evaluations were not performed, engineering studies and calculations were performed to evaluate the voltage impact of plant load additions and safety-related transformer tap changes. The current transformer tap settings were changed in accordance with the recommendations resulting from the 1986 degraded grid voltage study. Currently, this study is performed on an annual basis. The study is performed in accordance with the requirements of the NRC Generic Letter of August 8, 1979 entitled, "Adequacy of Station Electric Distribution System Voltages." 002450 HL-1885 E3 ENCLOSURE (Continued)
Reason for the Violation The violation was caused by the lack of a design document specifying 1E transformer tap settings.         As a result, transformer tap changes were implemented using Maintenance Work Orders (MWOs)           instead of the DCR process.     Consequently, formal 10 CFR 50.59 safety evaluations were not performed.       Plant personnel and architect/engineer personnel failed to realize the tap changes represented design changes.
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
The     transformer tap changes were implemented consistent with GPC's methodology     of establishing minimum and maximum ranges for offsite voltages. Although formal 10 CFR 50.59 safety evaluations were not performed, engineering studies and calculations were performed to evaluate the voltage impact of plant load additions and safety-related transformer tap changes.       The current transformer tap settings were changed in accordance with the recommendations resulting from the 1986 degraded grid voltage study. Currently, this study is performed on an annual basis. The study is performed in accordance with the requirements of the NRC Generic Letter     of August 8, 1979 entitled,         "Adequacy of Station Electric Distribution System Voltages."
50-366/91-202 Corrective Steps Which Have Been Taken and the Results Achieved In 1990 GPC identified the need to perform safety-related transformer tap changes as part of the DCR process. Consequently, on 2/21/91, drawings were issued to control changes to power transformer tap settings in accordance with the DCR process, thereby requiring the performance of formal 10 CFR 50.59 safety evaluations.
002450 HL-1885                               E3
Corrective Steps Which Will Be Taken to Avoid Further Violations Specific information for approximately 20 Class IE low-voltage transformers has not been included in the new drawings.
 
The necessary research and plant walkdowns will be performed to verify the remaining IE transformer tap settings.
ENCLOSURE (Continued)
Transformer inspections which do not require deenergization will be complete by 3/31/92. Examinations of transformers that require deenergization will be complete by the end of the next refueling outage for each unit. Drawings will be updated as necessary.
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Corrective Steps Which Have Been Taken and the Results Achieved In 1990 GPC identified the need to perform safety-related transformer tap changes as part of the DCR process.       Consequently, on 2/21/91, drawings were issued to control changes to power transformer tap settings in accordance with the DCR process, thereby requiring the performance of formal 10 CFR 50.59 safety evaluations.
Date When Refueling Full Compliance Will Be Achieved Full compliance for accessible transformer will be achieved by 3/31/92 when drawings will be issued. The remaining transformers will be included on the drawings by the next refueling outage. This will require the performance of 10 CFR 50.59 safety evaluations for future transformer tap changes.EXAMPLE c: Example c is considered a violation and occurred as described in the Notice of Violation.
Corrective Steps Which Will Be Taken to Avoid Further Violations Specific information for approximately 20 Class IE low-voltage transformers has not been included in the new drawings. The necessary research and plant walkdowns will be performed to verify the remaining IE transformer tap settings. Transformer inspections which do not require deenergization will be complete by 3/31/92. Examinations of transformers that require deenergization will be complete by the end of the next refueling outage for each unit. Drawings will be updated as necessary.
Reason for the Violation The violation was caused by personnel error. GPC protection engineering personnel did not sufficiently evaluate the coordination of the EDG overcurrent protection relays with the protective relays for the downstream circuit breakers.
Date When Refueling Full Compliance Will Be Achieved Full compliance for accessible transformer will be achieved by 3/31/92 when drawings will be issued. The remaining transformers will be included on the drawings by the next refueling outage.           This will require the performance of 10 CFR 50.59 safety evaluations for future transformer tap changes.
Additionally, GPC protection engineering personnel failed to identify the incorrect coordination during their review of the Appendix R Fire Protection Study which was performed in 1985. GPC personnel did not sufficiently evaluate the coordination scheme to ensure the required coordination was achieved.As discussed during the inspection, the overcurrent relay protection on the five emergency diesel generator (EDG) output circuit breakers was functionally coordinated with the relay protection on the downstream 002450 HL-1885 E4 ENCLOSURE (Continued)
EXAMPLE c:
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
Example c is considered a violation and occurred as described in the Notice of Violation.
50-366/91-202 breakers, with the exception of postulated faults such as a high impedance fault, a sluggish motor start with extended current draw near locked rotor current, or a continuous locked rotor condition on the associated 4160-V pump motors. These type scenarios are evaluated under single-failure analyses.The single-failure criterion applicable to this issue is based on ANSI/ANS 52.1, "Nuclear Safety Criteria for the Design of Stationary Boiling Water Reactor Plants." Section 3.2.1 states: The single failure criterion requires that the plant be capable of achieving (1) emergency core reactivity, control, (2) emergency core and containment heat removal and (3) containment isolation, integrity, and atmospheric cleanup given an initiating occurrence plus an independent single failure of a nuclear safety related component in any one of the systems required to support directly or indirectly these three nuclear safety functions (i.e. only one single failure need to be assumed in the plant nuclear safety related equipment for any initiating occurrence).
Reason for the Violation The violation was caused by personnel error. GPC protection engineering personnel did not sufficiently evaluate the coordination of the EDG overcurrent protection relays with the protective relays for the downstream circuit breakers.     Additionally, GPC protection engineering personnel failed to identify the incorrect coordination during their review of the Appendix R Fire Protection Study which was performed in 1985.             GPC personnel did not sufficiently evaluate the coordination scheme to ensure the required coordination was achieved.
ANSI/ANS 52.1 Is related to the specific question as follows: For a given initiating occurrence, GPC is required to ensure no single equipment failure will prevent adequate core cooling or adversely affect containment integrity.
As discussed during the inspection, the overcurrent relay protection on the five   emergency diesel generator (EDG)     output   circuit breakers was functionally coordinated with the relay protection on the downstream 002450 HL-1885                             E4
The failure is not specifically stated; therefore, the failure of any single piece of equipment must be considered credible.For Plant Hatch, one of the limiting single failures is the total loss of an EDG. The hypothetical loss of an EDG can be from any cause. An EDG failure may be initiated by several different sources; for example, from a start signal failure or a fault on the load side of a 4-kV breaker, or other component failures.The loss of an EDG is an analyzed event. All Appendix K requirements are satisfied, and containment integrity is not violated.
 
The key Issue for single failure is that it may occur prior to, during (simultaneously), or subsequent to the initiating (accident) event. The scenario must be analyzed for the most severe chronological occurrence of events so the plant successfully achieves mitigation of the accident.While the loss of an EDG due to less than fully adequate breaker coordination is an undesirable event, GPC maintains that such a scenario is within the licensing basis of the plant.002450 HL-1885 E5 ENCLOSURE (Continued)
ENCLOSURE (Continued)
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPQRT 50-321191-202:
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 breakers, with the exception of postulated faults such as a high impedance fault, a sluggish motor start with extended current draw near locked rotor current, or a continuous locked rotor condition on the associated 4160-V pump motors. These type scenarios are evaluated under single-failure analyses.
50-366/91-202 Corrective SteDs Which Have Been Taken and the Results Achieved Design Change Requests 91-124 and 91-125 were implemented on 7/12/91 to revise the settings on the diesel generator output breakers to correctly coordinate the protective devices.Corrective Steps Which Will Be Taken to Avoid Further Violations No further corrective actions are required.Date When Full Compliance Will Be Achieved Full compliance was achieved on 7/12/91 when DCRs 91-124 and 91-125 were implemented.
The single-failure criterion applicable to this issue is based on ANSI/ANS 52.1, "Nuclear Safety Criteria for the Design of Stationary Boiling Water Reactor Plants." Section 3.2.1 states:
EXAMPLE d: Example d is considered a violation and occurred as described in the Notice of Violation.
The single failure criterion requires that the plant be capable of achieving (1) emergency core reactivity, control, (2) emergency core and containment heat removal and (3) containment isolation, integrity, and atmospheric cleanup given an initiating occurrence plus an independent single failure of a nuclear safety related component in any one of the systems required to support directly or indirectly these three nuclear safety functions (i.e. only one single failure need to be assumed in the plant nuclear safety related equipment for any initiating occurrence).
Reason for the Violation The violation was caused by personnel error. Electrical calculation No. 87 (Bechtel), Revision 3, dated January 8, 1990, identifies various acceptable configurations between existing upstream circuit breakers and downstream fuses for 120-Vac and 125-Vdc control circuits.
ANSI/ANS 52.1 Is related to the specific question as follows:
Although no use of this calculation to select new fuse/breaker combinations is believed to exist, the intended us of the coordination tables was not adequately defined, and could have been misinterpreted.
For a given initiating occurrence, GPC is required to ensure no single equipment failure will prevent adequate core cooling or adversely affect containment integrity. The failure is not specifically stated; therefore, the failure of any single piece of equipment must be considered credible.
This calculation is not a basis for selecting fuse/breaker combinations in circuits where coordination is mandatory (i.e., Appendix R).Corrective SteDs Which Have Been Taken and the Results Achieved Electrical calculation No. 87 has been revised to clearly state its scope and purpose. The revision ensures that further reviews, if required, will be performed when undertaking coordination studies using this calculation.
For Plant Hatch, one of the limiting single failures is the total loss of an EDG. The hypothetical loss of an EDG can be from any cause.       An EDG failure may be initiated by several different sources; for example, from a start signal failure or a fault on the load side of a 4-kV breaker, or other component failures.
Additionally, a review was performed during the inspection and it is believed that the area of concern (overlapping of trip curves at relatively high fault levels) does not apply to any actual plant circuits.002450 HL-1885 E6 ENCLOSURE (Continued)
The loss of an EDG is an analyzed event. All Appendix K requirements are satisfied, and containment integrity is not violated. The key Issue for single failure is that it may occur prior to, during (simultaneously), or subsequent to the initiating (accident) event. The scenario must be analyzed for the most severe chronological occurrence of events so the plant successfully achieves mitigation of the accident.
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202:
While the loss of an EDG due to less than fully adequate breaker coordination is an undesirable event, GPC maintains that such a scenario is within the licensing basis of the plant.
50-366/91-202 Corrective SteDs Which Will Be Taken to Avoid Further Violations A review of the calculation will be performed to ensure it did not result in misapplications which cause an inappropriate level of coordination.
002450 HL-1885                             E5
This action will be complete by 3/31/92. Appropriate A/E personnel have been. counseled regarding the need for correctly translating design information.
 
Date When Full Compliance Will Be Achieved Full compliance was achieved on 10/30/91 when Electrical Calculation No. 87 was revised to more clearly state its scope and purpose.002450 HL-1885 E7 GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 I. INTRODUCTION S. J. BETHAY II. BACKGROUND AND CURRENT STATUS III. OFFSITE POWER SYSTEM IV. OPTIONS CONSIDERED V.  
ENCLOSURE (Continued)
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPQRT 50-321191-202: 50-366/91-202 Corrective SteDs Which Have Been Taken and the Results Achieved Design Change Requests 91-124 and 91-125 were implemented on 7/12/91 to revise the settings on the diesel generator output breakers to correctly coordinate the protective devices.
Corrective Steps Which Will Be Taken to Avoid Further Violations No further corrective actions are required.
Date When Full Compliance Will Be Achieved Full compliance was achieved on   7/12/91 when DCRs 91-124 and 91-125 were implemented.
EXAMPLE d:
Example d is considered a violation and occurred as described in the Notice of Violation.
Reason for the Violation The violation was caused by personnel error. Electrical calculation No. 87 (Bechtel), Revision 3, dated January 8, 1990, identifies various acceptable configurations between existing upstream circuit breakers and downstream fuses for 120-Vac and 125-Vdc control circuits. Although no use of this calculation to select new fuse/breaker combinations is believed to exist, the intended us of the coordination tables was not adequately defined, and could have been misinterpreted.       This calculation is not a basis for selecting fuse/breaker combinations in circuits where coordination is mandatory (i.e., Appendix R).
Corrective SteDs Which Have Been Taken and the Results Achieved Electrical calculation No. 87 has been revised to clearly state its scope and purpose. The revision ensures that further reviews, if required, will be performed when undertaking coordination studies using this calculation.
Additionally, a review was performed during the inspection and it is believed that the area of concern (overlapping of trip curves at relatively high fault levels) does not apply to any actual plant circuits.
002450 HL-1885                           E6
 
ENCLOSURE (Continued)
RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Corrective SteDs Which Will Be Taken to Avoid Further Violations A review of the calculation will   be performed to ensure it did not result in misapplications which cause     an inappropriate level of coordination.
This action will be complete by   3/31/92. Appropriate A/E personnel have been. counseled regarding the     need for correctly translating design information.
Date When Full Compliance Will Be Achieved Full compliance was achieved on 10/30/91 when Electrical Calculation No. 87 was revised to more clearly state its scope and purpose.
002450 HL-1885                           E7
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 I. INTRODUCTION                 S. J. BETHAY II. BACKGROUND AND               S. J. BETHAY CURRENT STATUS III. OFFSITE POWER SYSTEM         M. B. MILLER IV. OPTIONS CONSIDERED           T. 0. ANDERSON V.  


==SUMMARY==
==SUMMARY==
S. J. BETHAY M. B. MILLER T. 0. ANDERSON J. D. LIEIDT VI. OPEN DISCUSSION GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992  
J. D. LIEIDT VI. OPEN DISCUSSION
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992


==SUMMARY==
==SUMMARY==
I. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.
I. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.
II. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS.* RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM* SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES
II. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS.
* 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS
* RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM
(<101.3%)* AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT* ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT
* SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES
* FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ISSUE SUMIMARY I. DURING SUSTAINED DEGRADED GRID CONDITIONS AT OR SLIGHTLY ABOVE THE CURRENT SETPOINT, THE UNDERVOLTAGE PROTECTION WAS NOT CONSIDERED ADEQUATE TO ENSURE SAFETY-RELATED EQUIPMENT AT 600 VOLTS AND BELOW WOULD BE SUPPLIED WITH ADEQUATE VOLTAGE.* LOCA ACCIDENT CONDITIONS CONCURRENT WITH A DEGRADED GRID.
* 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS (<101.3%)
HYPOTHETICAL ALARM / TRIP RANGES MIN EXPECTED VOLTAGE ALARM SETPOINT TRIP SETP OINT MIN REQUIRED VOLTAGE 4.1 I6KV 290KV 104.9 103.5 101.9 96.7 EXP 92 ALARM 91 .4 91.14 90.8 REG EXP REG DEADBAND 88.94 I TRIP GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES I. ENSURE THE PLANT IS ADEQUATELY PROTECTED FROM UNDERVOLTAGE CONDITIONS." ASSESS THE LEVEL OF SAFETY PROVIDED BY THE CURRENT SYSTEM" IDENTIFY AVAILABLE OPTIONS" DETERMINE IF IMPROVEMENTS ARE FEASIBLE II. ENSURE OFFSITE POWER IS PRESERVED AS THE PREFERRED SOURCE.III. DEVELOP AN INTEGRATED APPROACH CONSIDERING THE ELECTRICAL DESIGN REQUIREMENTS, SYSTEM OPERATION AND PLANT OPERATION.
* AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT
* ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT
* FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ISSUE SUMIMARY I. DURING SUSTAINED DEGRADED GRID CONDITIONS AT OR SLIGHTLY ABOVE THE CURRENT SETPOINT, THE UNDERVOLTAGE PROTECTION WAS NOT CONSIDERED ADEQUATE TO ENSURE SAFETY-RELATED EQUIPMENT AT 600 VOLTS AND BELOW WOULD BE SUPPLIED WITH ADEQUATE VOLTAGE.
* LOCA ACCIDENT CONDITIONS CONCURRENT WITH A DEGRADED GRID.
 
HYPOTHETICAL ALARM / TRIP RANGES MIN EXPECTED VOLTAGE ALARM SETPOINT TRIP SETP OINT MIN REQUIRED VOLTAGE
 
4.1I6KV 290KV 104.9 96.7 EXP 103.5 101.9 92 ALARM 91 .4 REG 91.14 EXP 90.8 REG DEADBAND 88.94
 
I TRIP GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES I. ENSURE THE PLANT IS ADEQUATELY PROTECTED FROM UNDERVOLTAGE CONDITIONS.
      " ASSESS THE LEVEL OF SAFETY PROVIDED BY THE CURRENT SYSTEM
      " IDENTIFY AVAILABLE OPTIONS
      " DETERMINE IF IMPROVEMENTS ARE FEASIBLE II. ENSURE OFFSITE POWER IS PRESERVED AS THE PREFERRED SOURCE.
III. DEVELOP AN INTEGRATED APPROACH CONSIDERING THE ELECTRICAL DESIGN REQUIREMENTS, SYSTEM OPERATION AND PLANT OPERATION.
IV. AN UNDERVOLTAGE RELAY SETPOINT WITHIN THE NORMAL SYSTEM OPERATING RANGE IS UNACCEPTABLE.
IV. AN UNDERVOLTAGE RELAY SETPOINT WITHIN THE NORMAL SYSTEM OPERATING RANGE IS UNACCEPTABLE.
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES (CONTINUED)
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES (CONTINUED)
V. AN ORDERLY, FAST REACTOR SHUTDOWN IS PREFERABLE TO AN AUTOMATIC ISOLATION OR SELF INDUCED REACTOR ISOLATION TRANSIENT WITHOUT OFFSITE POWER.* SYSTEM OPERATORS SHOULD BE ALLOWED TO QUICKLY MITIGATE A DEGRADED GRID TRANSIENT TO AVOID AN UNNECESSARY ISOLATION TRANSIENT AND A FURTHER CHALLENGE TO GRID STABILITY.
V. AN ORDERLY, FAST REACTOR SHUTDOWN IS PREFERABLE TO AN AUTOMATIC ISOLATION OR SELF INDUCED REACTOR ISOLATION TRANSIENT WITHOUT OFFSITE POWER.
* SYSTEM OPERATORS SHOULD BE ALLOWED TO QUICKLY MITIGATE A DEGRADED GRID TRANSIENT TO AVOID AN UNNECESSARY ISOLATION TRANSIENT AND A FURTHER CHALLENGE TO GRID STABILITY.
* SYSTEM OPERATIONS SHOULD ASSESS THE CHALLENGE TO THE GRID AND DETERMINE IF QUALITY OFFSITE POWER CAN BE MAINTAINED.
* SYSTEM OPERATIONS SHOULD ASSESS THE CHALLENGE TO THE GRID AND DETERMINE IF QUALITY OFFSITE POWER CAN BE MAINTAINED.
VI. ENSURE RESOLUTION DOES NOT RESULT IN AN ACTUAL DECREASE IN OVERALL SAFETY.
VI. ENSURE RESOLUTION DOES NOT RESULT IN AN ACTUAL DECREASE IN OVERALL SAFETY.
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CRITERIA 1. RISKS ASSOCIATED WITH AN AUTOMATIC SHUTDOWN MUST BE BALANCED WITH THE RISKS ASSOCIATED WITH CONTINUED OPERATION.
II. RISKS ARE ASSIGNED AS A FUNCTION OF:* THE RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM'S GRID VS. RELIABILITY OF ONSITE POWER* THE SOUTHERN ELECTRIC SYSTEM'S GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES VS. SETPOINT CONTROLS* THE EXTREMELY LOW PROBABILITY OF DEGRADED VOLTAGE AT PLANT HATCH VS. THE POSSIBILITY OF SPURIOUS REACTOR ISOLATION TRANSIENTS ON THE PLANT* THE PROBABILITY OF OFFSITE VOLTAGE FALLING BELOW 101.3% IS 4.3X10-8* THE ANTICIPATED DURATION OF A DEGRADED GRID CONDITION* THE POTENTIAL EFFECT OF BRIEF DEGRADED VOLTAGE ON PLANT EQUIPMENT VS. THE EFFECT FROM AN ISOLATION TRANSIENT WITH 3 BUSSES AVAILABLE ON ONE UNIT AND 2 BUSSES ON THE OTHER* THE SYSTEM IMPACT OF SEPARATING 1600MW FROM A DEGRADED GRID GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ACTIONS COMPLETED I. HARDWARE AND SETPOINT CHANGES HAVE BEEN INVESTIGATED.
1I. WORKED WITH SYSTEM OPERATIONS TO GAIN AN UNDERSTANDING OF: " THE GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES" SYSTEM OPERATING PROCEDURES THAT ENSURE ADEQUATE VOLTAGE IS MAINTAINED" THE SYSTEM CONDITIONS WHICH WOULD HAVE TO OCCUR TO PRODUCE DEGRADED VOLTAGE AT PLANT HATCH III, INSTALL ANTICIPATORY ALARMS.IV. FORMALIZED ANTICIPATORY ACTION -BOTH ONSITE AND OFFSITE.V. FORMALIZED COMMUNICATIONS WITH SYSTEM OPERATIONS.
V-I IMPLEMENTED AN OPERATING ORDER TO ENSURE THE REACTOR IS QUICKLY BROUGHT TO A CONDITION OF GREATER SAFETY.* PROVIDES ACTIONS CONSISTENT WITH TECHNICAL SPECIFICATIONS ACTIONS FOR FAILURE OF ALL DIESEL GENERATORS


-H E ...... ..-AS OUTH E RN-E- EC-T-RiC SSYS-EM- (- SES)S5 OPERATING COMPANIES AGEORGI3A-7 POWER I. ,dk t ..SAVANNAH ,ELEC RIC-.-*,_, , -. -., ,r -.: -,, * -TOTAL4GENERATION.'  
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CRITERIA
-* HATCH'S IMPACTON*SY_-STEM
: 1. RISKS ASSOCIATED WITH AN AUTOMATIC SHUTDOWN MUST BE BALANCED WITH THE RISKS ASSOCIATED WITH CONTINUED OPERATION.
-.-. ---.-,- -~ -..
II. RISKS ARE ASSIGNED AS A FUNCTION OF:
SOUTHERN ELECTRIC SYSTEM (SES) SECURITY S"OPERATION CENTERS* ON LINE COMPUTERIZED LIBRARY OF REGIONAL AND SUBSTATION SINGLE LINES-..O CONTINUOUS MONITORING AND CONTINGENCY ANALYSIS.&#xf7; -. ... ... ..K -. ., ... ., .. -.. .., .......--.. .
* THE RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM'S GRID VS. RELIABILITY OF ONSITE POWER
BOTH UNITS ON-LINE~CHER RFATO~kGA.
* THE SOUTHERN ELECTRIC SYSTEM'S GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES VS. SETPOINT CONTROLS
500KV.r-A"J 1 .0 MVAR r--/VVi I r~i I''. 11VAR KL'3t.IPI~FI-.r JIFTON 29.a~f 'UER742 .760 86 645 HATCH 290 (iFi I GEN 2---in HATCH90 I@48 5 4 Q 529.9 44 77 i-t.r t'w MREA(IORE-50 tWAR 1091 1194 I. -44 74 DJA c:Wi~fi\yidl.dgn Aug. 4, 1991 1B:45:S9 Vil rT-.I(- 1ii 'sI I TIHAL -1A1.III VAR 11~~~1i* +t$crHFRS RFACTOR;LOSS OF THALMANN ADUVAL GA. 5OOKV PP') 7 rJVVAAI1 55 1o~1VAR 4,.1 o0 rH/-A III 50o IlVAR 11, 1517, IlVAn a -1 V VV TITFTON 295.6 HATCH. 290 V(J~VI.E I,:74~2760 i t-WFN I :(GAI 2'I &#xfd;'HATCH 500 SOM01A IRE.978 518 I.o 1421 1 4831 REACTORS 151)' IVAR THAI hAlIII1.-~ I 41.1914 468 0",0-D'JVAL c:Namsff~grid2.dgn Aug.4, 1991 18:46:59!II J,)  
* THE EXTREMELY LOW PROBABILITY OF DEGRADED VOLTAGE AT PLANT HATCH VS. THE POSSIBILITY OF SPURIOUS REACTOR ISOLATION TRANSIENTS ON THE PLANT
.. v 1 FHIT:E: R.ACT.R LOSS OF THALMANN \ DUVAL. LOSS OF UNIT I.HRE R R GA. 500KV 1 -v,'gV--I i' W I' IVAR " r--' .:A l- 1'T. AIR..R OHl~ARA. 4 4 PIP,17 InI V 1 t t., S) I I,.i- -I..I01:{
* THE PROBABILITY OF OFFSITE VOLTAGE FALLING BELOW 101.3% IS 4.3X10- 8
rH " *ScIIEP~r( TIFTON22.* " SCHtERER , ITNi292.4.0 769 0 901 HATCH 290 GEN I GEN 2_ "HATCH 900 1959 455 '10.4 291 144 I 0 .MI-'- .I W I';Ici-I REACToRn I I, BONA IRE',, --" .. -THAI I IAIII -.1890* o 4479 0.DDUVAL= :Nmdsfi\grid3.dgn:
* THE ANTICIPATED DURATION OF A DEGRADED GRID CONDITION
Aug. 4. 1991 18:54:14................... "o I 11 I I j:1!I I Q1 I~1 I:*LOSS O* OHARA PP9'1 7 I ~O i~/Al'AI=1i* I-I BOIA1AIRq 10 NORTH i.1 f"2 1.'HACH :5MO 19 11 417,'.1 901'I li Ht.8., K- 1141c~.1 S RE~tCTORS,-
* THE POTENTIAL EFFECT OF BRIEF DEGRADED VOLTAGE ON PLANT EQUIPMENT VS. THE EFFECT FROM AN ISOLATION TRANSIENT WITH 3 BUSSES AVAILABLE ON ONE UNIT AND 2 BUSSES ON THE OTHER
~. * '-I .it TDDUVAL TLE)SH I, i i Lug. 4, 191 11:23:15 .-4 GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 IF 230KV SYSTEM FAILS BELOW 101.3%* RECEIVE LOW VOLTAGE ALARM a NOTIFY CONTROL ROOM AT PLANT HATCH* PUT CAPACITOR BANKS ON* TURN SHUNT REACTORS OFF 0 PUT COMBUSTION TURBINES (McMANUS)
* THE SYSTEM IMPACT OF SEPARATING 1600MW FROM A DEGRADED GRID
IN SERVICE* BRING OUT OF SERVICE ELEMENTS BACK TO SERVICE a REDUCE LOAD GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CONCEPTUAL MODIFICATIONS APPROXIMATE COST I. TAP CHANGES II. NEW RELAYS, CABLE AND / OR EQUIPMENT CHANGE OUT III. NEW LOAD SHED / BUS TRANSFER SCHEMES IV. RE ANALYSIS OF EXISTING LOAD AT LOWER VOLTAGE$ 250,000$ 500,000- $1 MILLION$1 -2 MILLION$1 -2 MILLION V. NEW MAJOR EQUIPMENT$ 10 MILLION 290KV '1.16KV 104.9 96.7 EXP 1095 101.9 40, 92 -ALARM 91.4 REQ 91.14 EXP 90.8 REQ DEADBAND 88.94 a--TRIP GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992  
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ACTIONS COMPLETED I. HARDWARE AND SETPOINT CHANGES HAVE BEEN INVESTIGATED.
1I. WORKED WITH SYSTEM OPERATIONS TO GAIN AN UNDERSTANDING OF:
    " THE GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES
    " SYSTEM OPERATING PROCEDURES THAT ENSURE ADEQUATE VOLTAGE IS MAINTAINED
      " THE SYSTEM CONDITIONS WHICH WOULD HAVE TO OCCUR TO PRODUCE DEGRADED VOLTAGE AT PLANT HATCH III,  INSTALL ANTICIPATORY ALARMS.
IV. FORMALIZED ANTICIPATORY ACTION - BOTH ONSITE AND OFFSITE.
V. FORMALIZED COMMUNICATIONS WITH SYSTEM OPERATIONS.
V-I  IMPLEMENTED AN OPERATING ORDER TO ENSURE THE REACTOR IS QUICKLY BROUGHT TO A CONDITION OF GREATER SAFETY.
* PROVIDES ACTIONS CONSISTENT WITH TECHNICAL SPECIFICATIONS ACTIONS FOR FAILURE OF ALL DIESEL GENERATORS
 
H E               ......         -        ..-
AS OUTH ERN-E- EC-T-RiC SSYS-EM-                                                 (-SES)
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GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 IF 230KV SYSTEM FAILS BELOW 101.3%
* RECEIVE LOW VOLTAGE ALARM a NOTIFY CONTROL ROOM AT PLANT HATCH
* PUT CAPACITOR BANKS ON
* TURN SHUNT REACTORS OFF 0 PUT COMBUSTION TURBINES (McMANUS)   IN SERVICE
* BRING OUT OF SERVICE ELEMENTS BACK TO SERVICE a REDUCE LOAD
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CONCEPTUAL MODIFICATIONS             APPROXIMATE COST I. TAP CHANGES                               $ 250,000 II. NEW RELAYS, CABLE           $ 500,000- $1 MILLION AND / OR EQUIPMENT CHANGE OUT III. NEW LOAD SHED / BUS               $1 - 2 MILLION TRANSFER SCHEMES IV. RE ANALYSIS OF EXISTING             $1 - 2 MILLION LOAD AT LOWER VOLTAGE V. NEW MAJOR EQUIPMENT                   $ 10 MILLION
 
290KV         '1.16KV 104.9 96.7 EXP 1095 101.9 40, 92 -     ALARM 91.4 REQ 91.14 EXP 90.8 REQ DEADBAND 88.94   a--     TRIP
 
GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992


==SUMMARY==
==SUMMARY==
I. GPC REQUESTS NRC APPROVAL OF ADMINISTRATIVE IMPLEMENTATION OF BRANCH TECHNICAL POSITION PSB-1.II. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.
 
III. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS." RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM" SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES" 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS
I. GPC REQUESTS NRC APPROVAL OF ADMINISTRATIVE IMPLEMENTATION OF BRANCH TECHNICAL POSITION PSB-1.
(<101.3%)" AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT" ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT IV. FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL GeorginePowr Company 40 Inverness Center ParBkway post Ofitoe Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 J. T. Beckham, Jr. Georgia Power Vice President  
II. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.
-Nuclear Hatch Project Ithe soC.nerl er E,.'., -November 22, 1993 Docket Nos. 50-321 HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
III. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS.
On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions.
      " RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM
The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the. current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure.
      " SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES
Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.
      " 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS
Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).
(<101.3%)
OC orgia Power U.S. Nuclear Regulatory Commission  
      " AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT
-.Page Two November 22, 1993.Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.
        " ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT IV. FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL
Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased.
 
In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required.
GeorginePowr Company 40 Inverness Center ParBkway post Ofitoe Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 J. T. Beckham, Jr.                                                               Georgia Power Vice President - Nuclear Hatch Project                                                               Ithe soC.nerl erE,.'., -
Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary.
November 22,     1993 Docket Nos.         50-321                                                           HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory Comrrm*ssion ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
Consequently, GPC does not consider further actions to be necessary.
On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.
The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.Sincerely, T.Beckham, Jr JKB/cr 004440  
During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the. current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.
Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.
As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).
 
OC orgia Power U.S. Nuclear Regulatory Commission                                         -.Page Two November 22,     1993
          .Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.
Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased. In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required. Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary. Consequently, GPC does not consider further actions to be necessary.
The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.
Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.
Sincerely, T.Beckham, Jr JKB/cr 004440


==Enclosure:==
==Enclosure:==
Degraded Grid Voltage Protection cc: (See next page.)
Georgia Power  A U.S. Nuclear Regulatory Commission                    Page Three November 22,    1993 cc:  GeorgWa Power Comvani Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear Regplaiog Commission, Washington,D.C.
MW. K. Jabbour, Licensing Project Manager - Hatch U.S. NuclearRegulatory Commission. Regiion II Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch
Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection BackUround The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC) implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided. This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.
Origin of the 1ssue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers. An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors. As a result, the control power fuses were blown when the 480 volt motors were signaled to start.
At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.
However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.
HL-4440                                      E-1


Degraded Grid Voltage Protection cc: (See next page.)
Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.
Georgia Power A U.S. Nuclear Regulatory Commission Page Three November 22, 1993 cc: GeorgWa Power Comvani Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear Regplaiog Commission, Washington, D.C.MW. K. Jabbour, Licensing Project Manager -Hatch U.S. Nuclear Regulatory Commission.
Additional information is contained in GPC's submittals dated September 17, 1976; January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.
Regiion II Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector
GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.
-Hatch Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection BackUround The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC)implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided.
EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts),
This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.
certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.
Origin of the 1ssue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers.
By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function. By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection. GPC concluded that a violation of NRC requirements did not exist based on the following:
An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors.
HL-4440                                      E-3
As a result, the control power fuses were blown when the 480 volt motors were signaled to start.At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.HL-4440 E-1 Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.Additional information is contained in GPC's submittals dated September 17, 1976;January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function.
 
By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection.
Enclosure Degraded Grid Voltage Protection
GPC concluded that a violation of NRC requirements did not exist based on the following:
: 1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.
HL-4440 E-3 Enclosure Degraded Grid Voltage Protection
: 2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained. In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected. At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.
: 1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained.
Consequently, tap changes were made for the startup transformers in 1986 and 1987.
In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected.
Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4.160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected IE system voltages are, generally, slightly higher than the bus voltages submitted in 1980.
At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.Consequently, tap changes were made for the startup transformers in 1986 and 1987.Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4.160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected I E system voltages are, generally, slightly higher than the bus voltages submitted in 1980.3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
: 3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
: 4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible.
: 4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible. GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would represent a marginal to safety improvement. This conclusion is based on the following:
GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would represent a marginal to safety improvement.
A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone. The Southern electric system employs state-B-.4440                                        E-4
This conclusion is based on the following:
 
A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone.
Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis' feature allows system operation to predict adverse affects from postulated system failures. Based on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion. Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes.
The Southern electric system employs state-B-.4440 E-4 Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis' feature allows system operation to predict adverse affects from postulated system failures.
      " System operators receive low voltage alarm.
Based on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion.
* System operators notify the control room at Plant Hatch.
Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes." System operators receive low voltage alarm.* System operators notify the control room at Plant Hatch.* The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off).* The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).* Capacitor banks in the surrounding area are turned on (if oft).* Combustion turbines at Plant McManus are placed in service.These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:* Out of service elements are brought back on line.* System load (external or internal) is reduced.Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.HIL-4440 E-5 Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs), limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management.
* The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off).
The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored.
* The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).
The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-SI1-001-OS, "Operation With Degraded System Voltage." Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.
* Capacitor banks in the surrounding area are turned on (if oft).
This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks.
* Combustion turbines at Plant McManus are placed in service.
During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440 E-6 Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent).
These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:
At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation.
* Out of service elements are brought back on line.
The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion.
* System load (external or internal) is reduced.
Corrective actions have been taken to clarify this requirement and assure proper communications.
Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.
HL-4440 E-7 Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.
HIL-4440                                      E-5
* The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.* The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted." The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed." If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred.
 
However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation.
Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs),
In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been increased.
limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management. The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored. The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-SI1-001-OS, "Operation With Degraded System Voltage."
C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable.
Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.
This conclusion is based on the following:
This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.
HL-4440 E-8 Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required.
An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.
GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.
During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440                                         E-6
Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available.
 
Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection.
Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.
As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications.
The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.
Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.
GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.
GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint.
As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.
While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440 E-9-._
Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion. Corrective actions have been taken to clarify this requirement and assure proper communications.
Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected.
HL-4440                                      E-7
Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.
 
Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved: " The electrical requirements of safety-related equipment." The reliability of the offsite power supply." The potential adverse effects to the plant caused by an unnecessary disconnect from the offisite power source." The extremely low probability of a sustained degraded grid event concurrent with a LOCA.* The impact to the offisite power system caused by separating up to 1600 MW during a degraded grid event.As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure.
Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.
GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would likely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum* required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.
* The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.
HL-4440 E-10 ATTACHMENT 1 EDWIN 1. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution
* The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.
      " The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.
      " If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred. However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.
Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.
The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation. In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been increased.
C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable. This conclusion is based on the following:
HL-4440                                      E-8
 
Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required. GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.
Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available. Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection. As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications. Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.
GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint. While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440                                      E-9-._
 
Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected. Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.
Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved:
" The electrical requirements of safety-related equipment.
" The reliability of the offsite power supply.
" The potential adverse effects to the plant caused by an unnecessary disconnect from the offisite power source.
" The extremely low probability of a sustained degraded grid event concurrent with a LOCA.
* The impact to the offisite power system caused by separating up to 1600 MW during a degraded grid event.
As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would likely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum
*required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.
HL-4440                                        E-10
 
ATTACHMENT 1 EDWIN 1. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION
 
Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution System Description Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.
The GPC system is also designed to connect generating units to the grid at optimum locations. This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.
The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.
The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided in Figure 1.
Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.
The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.
The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.
The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, R.HR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.
HL-4440                                            A-!I
 
Attachment I Electrical System Description During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C.. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.
During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.
During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.
  -L-4440                                        A-2
 
me        Ia.      In. Ifl.
M~ *~S 4-.'.'-
oooA, Z.m-m                                                      0; Is -oak
                                                                                -S
*1-13{50 - UNIT I      MIAIN POWER DISTRIBUJTION                                  M&IN POW"fR IISFIIJIIaI.
EDWIN I nATCH - UNII 2                                      EDWIN 4 IIAIC.  -  4 I "4I I-I-2950 - UNIT 2 FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS - NORMAL OPERATION
 
ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARM/TRIP RANGES
 
HYPOTHETICAL ALARM / TRIP RANGES NUN EXPECTED VOLTAGE ALARM SETPOIN'T TRIP SETPOINT MEN REQUIRED VOLTAGE
 
ATTACHMENT 3 EDWIN 1. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS
 
P~ant Hatch Unit 1      Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E    DEAD BAND CALC, 92764PG
 
P~ant Hat+/-ch Unit    1    Bus-F 4.16KV 97.6 EXP 104.9 103.5 101,3 ALARM 88.47 REQ E    DEAD BAND CALC. 92764PG
 
Plant    Ha~tch  Unit 1      Bus G
                            ,'V 97.6 EXP 104.9 103.5          (-
101.3 ALARM
                            .. 91.4 RE 0 9
9D SDEAD BAND CALC. 92764PG
 
I Ptant Haoch Unit 2            Bus- E 4.16KV 230KV 97.85 EXP 104.9 103.5 101.3 93.81 EXP ALARM 90.73 REQ 90.05 REQ 7
88.34 I    i M    DEAD BAND CALC, 92763PG
 
Georgia Power Company 40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279                                                                              A J. T. O.c.am, J,.
Vice President - Nuclear Georgia Power Hatch Project                          July 1,    1994                          Ihe SoLthern electrfc systern Docket Nos. 50-321                                                                        HL-4586 50-366 TAC No.          80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1.Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.
The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.


===System Description===
'orgia Power    A U.S. Nuclear Regulatory Commission                                                Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.
Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.The GPC system is also designed to connect generating units to the grid at optimum locations.
GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the offsite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to the initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-I of the Unit I and Unit 2 Technical Specifications, respectively.
This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.
GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband. Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement. If voltages are not restored within one hour, a plant shutdown is then initiated.
The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided in Figure 1.Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, R.HR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.
HL-4440 A-!I Attachment I Electrical


===System Description===
ll
During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C.. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.
  .'orgiaPower  A U.S. Nuclear Regulatory Commission                                             Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into the Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications. Accordingly, the limiting condition of operation (LCO) will require the degraded grid alarms to be operable in modes 1, 2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable. Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.
During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.-L-4440 A-2 M~ *~S me Ia. In. Ifl.4-.'.'-oooA, Z.m-m 0; Is -oak-S-UNIT I I-I-2950 -UNIT 2 MIAIN POWER DISTRIBUJTION M&IN POW"fR IISFIIJIIaI.
Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded. GPC has evaluated this request to raise the alarm setpoints to 97 percent of4160 volts and determined that it is not feasible nor required. The basis for this conclusion is as follows:
EDWIN I nATCH -UNII 2 EDWIN 4 IIAIC. -"4I 4 I FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS
The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required. As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.
-NORMAL OPERATION ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARM/TRIP RANGES HYPOTHETICAL ALARM / TRIP RANGES NUN EXPECTED VOLTAGE ALARM SETPOIN'T TRIP SETPOINT MEN REQUIRED VOLTAGE ATTACHMENT 3 EDWIN 1. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS P~ant Hatch Unit 1 Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E DEAD BAND CALC, 92764PG P~ant Hat+/-ch Unit 4.16KV 1 Bus-F 97.6 EXP 104.9 103.5 101,3 ALARM 88.47 REQ E DEAD BAND CALC. 92764PG Plant Ha~tch 104.9 103.5 (-101.3 9 9D SDEAD BAND Unit 1 Bus G ,'V 97.6 EXP..91.4 RE 0 ALARM CALC. 92764PG I Ptant Haoch Unit 2 Bus- E 4.16KV 230KV 104.9 103.5 101.3 93.81 EXP 97.85 EXP ALARM 90.05 REQ 88.34 I 7 i 90.73 REQ M DEAD BAND CALC, 92763PG Georgia Power Company 40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 A J. T. O.c.am, J,. Georgia Power Vice President
-Nuclear Hatch Project July 1, 1994 Ihe SoLthern electrfc systern Docket Nos. 50-321 HL-4586 50-366 TAC No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions.
By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.
The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.
'orgia Power A U.S. Nuclear Regulatory Commission Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the offsite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to the initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-I of the Unit I and Unit 2 Technical Specifications, respectively.
GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband.
Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement.
If voltages are not restored within one hour, a plant shutdown is then initiated.
ll.'orgia Power A U.S. Nuclear Regulatory Commission Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into the Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications.
Accordingly, the limiting condition of operation (LCO) will require the degraded grid alarms to be operable in modes 1, 2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable.
Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded.
GPC has evaluated this request to raise the alarm setpoints to 97 percent of4160 volts and determined that it is not feasible nor required.
The basis for this conclusion is as follows: The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required.
As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.
As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.
As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.
r'*orgia PowerA U.S. Nuclear Regulatory Commission Page Four July 1, 1994 The current alarm setpoints of approximately 92 to 93 percent of 4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions.
 
The current alarm setpoint values signify that adequate voltage is available for normal operations.
r'*orgia PowerA U.S. Nuclear Regulatory Commission                                             Page Four July 1, 1994 The current alarm setpoints of approximately 92 to 93 percent of 4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions. The current alarm setpoint values signify that adequate voltage is available for normal operations. Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-00 1-OS, "Operation With Degraded System Voltage" if the voltage cannot be restored. Procedure 34AB-SI 1-001-OS directs operators to initiate a "one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation. An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers. From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.
Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-00 1-OS, "Operation With Degraded System Voltage" if the voltage cannot be restored.
Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint. Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.
Procedure 34AB-SI 1-001-OS directs operators to initiate a"one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation.
Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation.             As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations. GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.
An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers.
 
From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.
!orgia Power A U.S. Nuclear Regulatory Commission                                       Page Five July 1, 1994 Should you have any questions in this regard, please contact this office.
Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint.
Sincerely, Jr.
Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation.
                                                      ? J.T. Beckhani, MKB/cr cc: GeorgiaPower Compa-nv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS U.S. NuclearRegulatory Commission. Washington. D.C.
As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations.
Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Reyloaoro Commission. Region I)
GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.  
Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector - Hatch
!orgia Power A U.S. Nuclear Regulatory Commission Page Five July 1, 1994 Should you have any questions in this regard, please contact this office.Sincerely,? J. T. Beckhani, Jr.MKB/cr cc: Georgia Power Compa-nv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS U.S. Nuclear Regulatory Commission.
 
Washington.
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 10, 1995 LICENSEE: Georgia Power Company, et al.
D.C.Mr. K. Jabbour, Licensing Project Manager -Hatch U.S. Nuclear Reyloaoro Commission.
FACILITY: Hatch Nuclear Plant, Units 1 and 2
Region I)Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector  
-Hatch UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 10, 1995 LICENSEE:
Georgia Power Company, et al.FACILITY:
Hatch Nuclear Plant, Units 1 and 2  


==SUBJECT:==
==SUBJECT:==


==SUMMARY==
==SUMMARY==
OF DECEMBER 7, 1994, MEETING WITH GEORGIA POWER COMPANY ON DEGRADED GRID VOLTAGE -HATCH NUCLEAR PLANT, UNITS I AND 2 (TAC NO. M80948)On December 7, 1994, the NRC staff met with Georgia Power Company (GPC or licensee) representatives and their consultant from Southern Company Services (SCS) in Birmingham, Alabama, to discuss equipment operability under degraded grid conditions at Plant Hatch, Units 1 and 2. Attachment 1 lists the attendees and Attachment 2 contains a copy of the vlewgraphs used by the licensee during the presentation.
OF DECEMBER 7, 1994, MEETING WITH GEORGIA POWER COMPANY ON DEGRADED GRID VOLTAGE - HATCH NUCLEAR PLANT, UNITS I AND 2 (TAC NO. M80948)
After brief introductory remarks by NRC and GPC regarding the objectives of the meeting, Mr. J. Branum, GPC, provided a summary of previous correspondence and meetings regarding the same subject. He stated that NRR staff's concerns originated from an electrical distribution system functional inspection completed in July 1991. He discussed the licensing basis associated with the existing setpolnt for the degraded grid undervoltage relays and GPC's concerns when raising the setpoint.Georgia Power's concerns are based on the low probability of a sustained degraded grid event combined with a loss-of-coolant accident, the existing narrow range between the minimum expected voltage and the minimum required voltage, the possibility of introducing unnecessary trips of the offsite power supply, and the need for major plant modifications.
On December 7, 1994, the NRC staff met with Georgia Power Company (GPC or licensee) representatives and their consultant from Southern Company Services (SCS) in Birmingham, Alabama, to discuss equipment operability under degraded grid conditions at Plant Hatch, Units 1 and 2. Attachment 1 lists the attendees and Attachment 2 contains a copy of the vlewgraphs used by the licensee during the presentation.
Mr. Branum also discussed the methods for maintaining the minimum required switchyard voltage, the basis for the setpoint of the undervoltage alarm relays, plant procedures for responding to a degraded grid event, and the incorporation of the alarm setpoint into the improved Technical Specifications.
After brief introductory remarks by NRC and GPC regarding the objectives of the meeting, Mr. J. Branum, GPC, provided a summary of previous correspondence and meetings regarding the same subject. He stated that NRR staff's concerns originated from an electrical distribution system functional inspection completed in July 1991. He discussed the licensing basis associated with the existing setpolnt for the degraded grid undervoltage relays and GPC's concerns when raising the setpoint.
During a followup discussion, Messrs. S. Bethay, GPC, and B. Snider, SCS, provided additional details of the alarm setpoint.
Georgia Power's concerns are based on the low probability of a sustained degraded grid event combined with a loss-of-coolant accident, the existing narrow range between the minimum expected voltage and the minimum required voltage, the possibility of introducing unnecessary trips of the offsite power supply, and the need for major plant modifications. Mr. Branum also discussed the methods for maintaining the minimum required switchyard voltage, the basis for the setpoint of the undervoltage alarm relays, plant procedures for responding to a degraded grid event, and the incorporation of the alarm setpoint into the improved Technical Specifications.
The setpoint is set as high as practical to provide notification of bn'undervoltage*
During a followup discussion, Messrs. S. Bethay, GPC, and B. Snider, SCS, provided additional details of the alarm setpoint. The setpoint is set as high as practical to provide notification of bn'undervoltage* condition during normal operation but also to avoid unnecessary alarms whirl the balance-of-plant equipment is powered from the startup transformers. Mr. Bethay also discussed the ability of the plant to respond to a postulated undervoltage condition. His statements were based on the pl-'at's responrse to a station blackout condition where the pressure systems provide inventory makeup. These systems rely on DC power rather than AC power. Georgia Power concluded the meeting by stating that the existing degraded grid-rotectlon system is adequate and that further modifications are not necessary.
condition during normal operation but also to avoid unnecessary alarms whirl the balance-of-plant equipment is powered from the startup transformers.
 
Mr. Bethay also discussed the ability of the plant to respond to a postulated undervoltage condition.
The NRC staff had several comments regarding the alarm and the operator actions. In addition, the staff requested that the Final Safety Analysis Report (FSAR) be amended to provide information on GPC's approach to degraded grid protection which should include a discussion of the alarms and the operating range at the 230 KV level. GPC agreed to update the FSAR.
His statements were based on the pl-'at's responrse to a station blackout condition where the pressure systems provide inventory makeup. These systems rely on DC power rather than AC power. Georgia Power concluded the meeting by stating that the existing degraded grid-rotectlon system is adequate and that further modifications are not necessary. The NRC staff had several comments regarding the alarm and the operator actions. In addition, the staff requested that the Final Safety Analysis Report (FSAR) be amended to provide information on GPC's approach to degraded grid protection which should include a discussion of the alarms and the operating range at the 230 KV level. GPC agreed to update the FSAR.At the conclusion of the meeting, the NRC staff stated that they will review GPC's submittal and the handouts with the view that the approach proposed by GPC constitutes a deviation from the recommendations of the Generic Letter dated June 2, 1977.Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects -I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366 Attachments:
At the conclusion of the meeting, the NRC staff stated that they will review GPC's submittal and the handouts with the view that the approach proposed by GPC constitutes a deviation from the recommendations of the Generic Letter dated June 2, 1977.
: 1. List of Attendees 2. Viewgraphs cc w/Attachments:
Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366 Attachments:   1. List of Attendees
See next page Georgia Power Company cc:.Mr. Ernest L. Blake, Jr.Shaw, Plttman, Potts and 2300 N Street, NW.Washington, DC 20037 Trowbridge Mr. S. J. Bethay Manager Licensing
: 2. Viewgraphs cc w/Attachments:   See next page
-Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201 Mr. L. Sumner General Manager, Nuclear Plant Georgia Power Company Route 1, Box 439 Baxley, Georgia 31513 Edwin I. Hatch Nuclear Plant Mr. Ernie Toupin Manager of Nuclear Operations Oglethorpe Power Corporation 2100 East Exchange Place Tucker, Georgia 30085-1349 Charles A. Patrizia, Esquire Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW.Washington, DC 20036 Mr. Jack 0. Woodard Senior Vice President  
 
-Nuclear Operations Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201 Chairman Appling County Commissioners County Courthouse Baxley, Georgia 31513 Mr. J. T. Beckham, Jr.Vice President
Georgia Power Company               Edwin I. Hatch Nuclear Plant cc:.                               Mr. Ernie Toupin Mr. Ernest L. Blake, Jr.           Manager of Nuclear Operations Shaw, Plttman, Potts and Trowbridge Oglethorpe Power Corporation 2300 N Street, NW.                 2100 East Exchange Place Washington, DC 20037               Tucker, Georgia 30085-1349 Mr. S. J. Bethay                   Charles A. Patrizia, Esquire Manager Licensing - Hatch          Paul, Hastings, Janofsky & Walker Georgia Power Company              12th Floor P. 0. Box 1295                      1050 Connecticut Avenue, NW.
-Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201 Resident Inspector U.S. Nuclear Regulatory Route 1, Box 725 Baxley, Georgia 31513 Commission Regional Administrator, Region II U.S. Nuclear Regulatory Commission 101 Marietta Street, NW. Suite 2900 Atlanta, Georgia 30323 Mr. Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW.Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334 K. N. Jabbour 0. F. Thatcher N. K. Treham Gary McGaha Tom Sims Jeff Branum Bill Snider Roger Hayes David Gambrell Steve E. Bethay NRC/GPC MEETING DECEMBER 7. 1994 ORGANIZATION NRC/NRR NRC/NRR/EELB NRC/NRR/EELB SCS-Hatch SCS-CATS SNC/NEL SCS/Hatch SNC/Farley SCS-Farley SNC-Hatch Engineering Attachment I
Birmingham, Alabama 35201          Washington, DC 20036 Mr. L. Sumner                      Mr. Jack 0. Woodard General Manager, Nuclear Plant      Senior Vice President -
Edwin I. Hatch Nuclear Plant Degraded Grid Protection December 7, 1994 Agenda Introduction Overview of Correspondence/Meetings Selected Topics" Basis for existing setpoints" Concerns with raising setpoints" Plant procedures and technical specifications Discussion Conclusion J. D. Heidt J. K. Branum J. K. Branum All J.D. Heidt Attachment 2
Georgia Power Company                Nuclear Operations Route 1, Box 439                    Georgia Power Company Baxley, Georgia 31513               P. 0. Box 1295 Birmingham, Alabama 35201 Resident Inspector U.S. Nuclear Regulatory Commission  Chairman Route 1, Box 725                   Appling County Commissioners Baxley, Georgia 31513              County Courthouse Baxley, Georgia 31513 Regional Administrator, Region II U.S. Nuclear Regulatory Commission Mr. J. T. Beckham, Jr.
101 Marietta Street, NW. Suite 2900 Vice President - Plant Hatch Atlanta, Georgia 30323             Georgia Power Company P. 0. Box 1295 Mr. Charles H. Badger               Birmingham, Alabama 35201 Office of Planning and Budget Room 610 270 Washington Street, SW.
Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334
 
NRC/GPC MEETING DECEMBER 7. 1994 ORGANIZATION K. N. Jabbour  NRC/NRR
: 0. F. Thatcher  NRC/NRR/EELB N. K. Treham    NRC/NRR/EELB Gary McGaha    SCS-Hatch Tom Sims        SCS-CATS Jeff Branum    SNC/NEL Bill Snider    SCS/Hatch Roger Hayes    SNC/Farley David Gambrell  SCS-Farley Steve E. Bethay SNC-Hatch Engineering Attachment I
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection December 7, 1994 Agenda Introduction                                   J. D. Heidt Overview of Correspondence/Meetings             J. K. Branum Selected Topics                                 J. K. Branum
    " Basis for existing setpoints
    " Concerns with raising setpoints
    " Plant procedures and technical specifications Discussion                                     All Conclusion                                     J.D. Heidt Attachment 2
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings
: 1. EDSFI performed in May/June of 1991* NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnect from offsite power supply.2. GPC Meeting with NRC on 8/6/91" GPC discussed offsite system controls, extremely low probability of a sustained degraded grid and LOCA, and operating enhancements." NRC Staff indicated agreement with GPC's conclusions.
: 1. EDSFI performed in May/June of 1991
: 3. Inspection Report 91-202, dated 8/22/91* Restated EDSFI Team's concern 4. Notice of Violation, dated 10/7/91 5. GPC Reply to NOV, dated 11/6/91* Denied violation" GPC determined a violation of NRC requirements did not exist Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings (Continued)
* NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnect from offsite power supply.
: 6. GPC Meeting with NRC on 11/16/92" GPC provided objectives and criteria used in assessment." Detailed discussion of offsite system monitoring and controls* Actions completed* Cost estimates for conceptual modifications
: 2. GPC Meeting with NRC on 8/6/91
: 7. GPC letter, dated 11/22/93" Basis for existing setpoints* Basis for concerns for unnecessary disconnects
      " GPC discussed offsite system controls, extremely low probability of a sustained degraded grid and LOCA, and operating enhancements.
: 8. GPC letter, dated 7/1/94* Basis for alarm setpoints* Committed to include alarm in improved Technical Specifications
      "NRC Staff indicated agreement with GPC's conclusions.
* Formally requested NRC review and approval Edwin I. Hatch Nuclear Plant Degraded Grid Protection Selected Topics 1. Basis for existing undervoltage relay setpoints 2. Concerns with raising setpoints 3. Basis for alarm setpoints 4. Plant procedures and Technical Specifications Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints* Existing setpoints are in accordance with GPC's response to the NRC generic letter dated June 2, 1977" Existing setpoints were approved in the Safety Evaluation report dated 5/6/82" GPC used maximum plant loadings to establish the minimum expected voltage for the offsite power supply to assure the adequacy of plant voltage levels Edwin I. Hatch Nuclear Plant Degraded (rid Protection
: 3. Inspection Report 91-202, dated 8/22/91
* A sustained degraded grid is not a credible event for Plant Hatch The Southern Electric System employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure adequate voltage is provided and the contingency analysis feature allows prediction of the adverse affects from postulated system failures.* System operators configure the offsite power supply such that a failure can occur without adversely affecting the minimum required voltage. This includes postulated trips of a Hatch unit.e A dynamic voltage excursion is more likely Ptant Hatch Unit 1 Bus G 97.6 EXP 104.9 103.5 102.6 101,3 192.96 EXP ALARM 91.4 REQ DEGRADED GRID 8034 SETPOINT O DEAD BAND CALC. 94738PG Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints (Continued)" The occurrence of a sustained degraded grid is extremely unlikely" The occurrence of a LOCA is estimated at 2.61 x 10.4 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Concerns With Raising Undervoltage Relay Setpoints" The existing range between the minimum expected voltage with the grid at 101.3 percent and the minimum required voltage for LOCA loads is too narrow" Raising the setpoint could result in unnecessary and unwanted disconnects within the expected voltage range.* Raising the setpoint could result in a trip from the offsite power supply during a LOCA when offsite power is fully adequate.9 Increasing the narrow range would require major plant modifications Edwin I. Hatch Nuclear Plant Degraded Grid Protection Dynamic Excursion vs Sustained Degraded Grid The most likely degraded grid event is a dynamic voltage excursion For a dynamic voltage excursion, disconnecting both units from offsite power and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.GPC's method of using manual actions in the deadband range allows system operators to quickly stabilize a degraded grid without introducing a plant transient when offsite power is undergoing a temporary excursion and is not in actual jeopardy.
* Restated EDSFI Team's concern
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Conce2tual Modifications
: 4. Notice of Violation, dated 10/7/91
: 1. Transformer tap changes 2. New undervoltage relays, cable/equipment replacement
: 5. GPC Reply to NOV, dated 11/6/91
: 3. New major equipment Approximate Cost 250,000 500,000 -1 million 10 million Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Undervoltage alarm setpoint is as high as practical Setpoint is approximately midway between the minimum voltage for operation (BOP equipment on SAT's) and the expected voltage with the grid lowered to 101.3 percent (above 92 percent)A higher alarm setpoint of 97 percent would be expected to generate frequent false alarms when non-safety loads are powered from the startup transformers.
* Denied violation
The alarms are also expected to annunciate during a LOCA if the grid has lowered to 101.3 percent Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Alarm annunciation indicates that an undervoltage condition is present: However, voltage is adequate for normal operation (i.e., voltage levels, equipment performance, and availability of equipment is satisfactory).
      " GPC determined a violation of NRC requirements did not exist
Edwin I. Hatch Nuclear Plant Degraded Grid Protection ActfiQns Completed 1. Increasing the undervoltage relay setpoint and replacing the relays have been evaluated.
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings (Continued)
: 6. GPC Meeting with NRC on 11/16/92 "GPC provided objectives and criteria used in assessment.
      "Detailed discussion of offsite system monitoring and controls
* Actions completed
* Cost estimates for conceptual modifications
: 7. GPC letter, dated 11/22/93 "Basis for existing setpoints
* Basis for concerns for unnecessary disconnects
: 8. GPC letter, dated 7/1/94
* Basis for alarm setpoints
* Committed to include alarm in improved Technical Specifications
* Formally requested NRC review and approval
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Selected Topics
: 1. Basis for existing undervoltage relay setpoints
: 2. Concerns with raising setpoints
: 3. Basis for alarm setpoints
: 4. Plant procedures and Technical Specifications
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints
* Existing setpoints are in accordance with GPC's response to the NRC generic letter dated June 2, 1977 "Existing setpoints were approved in the Safety Evaluation report dated 5/6/82
  " GPC used maximum plant loadings to establish the minimum expected voltage for the offsite power supply to assure the adequacy of plant voltage levels
 
Edwin I. Hatch Nuclear Plant Degraded (rid Protection
* A sustained degraded grid is not a credible event for Plant Hatch The Southern Electric System employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure adequate voltage is provided and the contingency analysis feature allows prediction of the adverse affects from postulated system failures.
* System operators configure the offsite power supply such that a failure can occur without adversely affecting the minimum required voltage. This includes postulated trips of a Hatch unit.
e A dynamic voltage excursion is more likely
 
Ptant   Hatch Unit 1     Bus G 104.9                        97.6 EXP 103.5 102.6 101,3 192.96 EXP ALARM 91.4 REQ DEGRADED GRID 8034 SETPOINT O     DEAD BAND CALC. 94738PG
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints (Continued)
" The occurrence of a sustained degraded grid is extremely unlikely
" The occurrence of a LOCA is estimated at 2.61 x 10.4
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Concerns With Raising Undervoltage Relay Setpoints "The existing range between the minimum expected voltage with the grid at 101.3 percent and the minimum required voltage for LOCA loads is too narrow "Raising the setpoint could result in unnecessary and unwanted disconnects within the expected voltage range.
* Raising the setpoint could result in a trip from the offsite power supply during a LOCA when offsite power is fully adequate.
9 Increasing the narrow range would require major plant modifications
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Dynamic Excursion vs Sustained Degraded Grid The most likely degraded grid event is a dynamic voltage excursion For a dynamic voltage excursion, disconnecting both units from offsite power and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.
GPC's method of using manual actions in the deadband range allows system operators to quickly stabilize a degraded grid without introducing a plant transient when offsite power is undergoing a temporary excursion and is not in actual jeopardy.
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Conce2tual Modifications                     Approximate Cost
: 1. Transformer tap changes                       250,000
: 2. New undervoltage relays, cable/           500,000 - 1 million equipment replacement
: 3. New major equipment                             10 million
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Undervoltage alarm setpoint is as high as practical Setpoint is approximately midway between the minimum voltage for operation (BOP equipment on SAT's) and the expected voltage with the grid lowered to 101.3 percent (above 92 percent)
A higher alarm setpoint of 97 percent would be expected to generate frequent false alarms when non-safety loads are powered from the startup transformers.
The alarms are also expected to annunciate during a LOCA if the grid has lowered to 101.3 percent
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Alarm annunciation indicates that an undervoltage condition is present:
However, voltage is adequate for normal operation (i.e., voltage levels, equipment performance, and availability of equipment is satisfactory).
 
Edwin I. Hatch Nuclear Plant Degraded Grid Protection ActfiQns Completed
: 1. Increasing the undervoltage relay setpoint and replacing the relays have been evaluated.
: 2. Evaluated system operations grid monitoring and failure analysis capabilities.
: 2. Evaluated system operations grid monitoring and failure analysis capabilities.
: 3. Installed anticipatory alarms.4. Formalized anticipatory actions both onsite and offsite.5. Implemented annunciator response and abnormal operating procedures to ensure the reactor is quickly brought to a condition of greater safety.6. Incorporated the alarms into the improved technical specifications.
: 3. Installed anticipatory alarms.
: 4. Formalized anticipatory actions both onsite and offsite.
: 5. Implemented annunciator response and abnormal operating procedures to ensure the reactor is quickly brought to a condition of greater safety.
: 6. Incorporated the alarms into the improved technical specifications.
: 7. Installed an additional capacitator bank in the 230 Kv switchyard to provide three levels of adjustment.
: 7. Installed an additional capacitator bank in the 230 Kv switchyard to provide three levels of adjustment.
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Summary The existing degraded grid protection system using manual actions in the deadband area followed by automatic controls provides adequate safety.The existing system provides a higher level of safety when compared to automatic controls for more likely transient scenarios.
 
GPC has expended considerable resources to resolve NRR staff concerns.Further actions are not necessary.  
Edwin I. Hatch Nuclear Plant Degraded Grid Protection Summary The existing degraded grid protection system using manual actions in the deadband area followed by automatic controls provides adequate safety.
The existing system provides a higher level of safety when compared to automatic controls for more likely transient scenarios.
GPC has expended considerable resources to resolve NRR staff concerns.
Further actions are not necessary.


==1.0 IDENTIFICATION==
==1.0 IDENTIFICATION==
ALARM PANEL 652-1 4160V. BUS 1E VOLTAGE LOW DEVICE: SETPOINT: 1S32-K206-1/2 3867 volts 2.0 CONDITION:  
ALARM PANEL 652-1 4160V. BUS 1E VOLTAGE LOW DEVICE:                       SETPOINT:
1S32-K206-1/2                   3867 volts
 
==2.0 CONDITION==
 
===3.0 CLASSIFICATION===
A low voltage condition was sensed on 4160V BUS IE.                    EOUIPMENT STATUS
 
==4.0 LOCATION==
l~l1-P652 PANEL 652-1 5.0    OPERATOR ACTIONS:
5.1    Confirm that voltage is  less than 3867 volts on Panel 1111-P652 on 4160V BUS IE Voltmeter.
5.2  1E voltage is below 3867 volts; notify Georgia Control Center and request operator to raise the voltage on the system to normal.
5.3  If voltage on the system cannot be restored,    enter 34AB-SIl-OOl-OS,    Operation with Degraded System Voltage.
.6.0    CAUSES:
6.1    System voltage is  low
 
==7.0  REFERENCES==
8.0    TECH. SPEC./LCO:
7.1    H-13412,  Elementary Diagrams Diesel          8.1  3/4.9, Electrical Power Systems Gen IA DEPT. MGR                                      DATE  _                      34AR-652-122-IS IRev. 4 MGR-0048 Rev. I                                                          21DC-DCX-001-OS
 
GEORGIA POWER COMPANY                DOCUMENT TYPE:                                    PAGE    I OF  2 PLANT E.I. MATCH[                      ABNORMAL OPERATING PROCEDURE TITLE.                                              DOCUMENT NUMBER:        REVISION NO:
OPERATION WITH DEGRADED SYSTEM VOLTAGE                          34AB-Sll-001-os        I EXPIRATION DATE:          APPROVALS: MARKUP APPROVED BY:                                    EFFECTIVE DEPARTMENT MANAGER        J.C. LEWIS        DATE  3-19-93        DATE:
N/A GMNP/AGM-PO/AGK- PS            N/A            DA*3-19-93
__ _..r-
___                    -r, r*v,- ^* .r" 1.0    CONDITIONS 1          S':?,~      SUPORT SO r..-jQ11N1NT CONTROL
                                                                  ?V~
I Normal minmum voltage with either Unit in modem 1, 2, or 3 in 233KV. Normal minimum voltage with both units in COLD SHUTDOWN, REFUEL or with Fuel Ramved is  225KV.
1.1    The System Operating Center (Birmingham) ham notified the Superintendent On Shift that the Offmite Distribution System is in jeopardy of ZM being able to maintain normal minimum voltage at the 230KV bum.
1.2      The System Operating Center has notified the Superintendent On Shift that the 230KV Bus voltage C                be maintained above normal minimum voltage.
2.0    AUTOMATIC ACTIONS None 3.0    I!4EDIATE OPERATOR ACTIONS N/A - not applicable to this procedure.
4.0    SUBSEOUENT OPERATOR ACTIONS 4.1      Upon notification from System Operating Center that the Offmite Distribution System is one contingency (event) away from being unable to maintain normal minimum voltage on the 230KV bus,                the following action. are to be taken:
4 .1.1      RETURN inoperable Emergency Diesel Generators to operable status as soon an possible.
4.1.2      NO maintenance QS surveillance is to be initiated an critical comonents of the on-mite electrical distribution system AM those in process are to be RESTORED to normal an TZiIMRTED as moow am possible.
4.1.3      ASSIGN an operator to monitor the voltage indicators for the mix 4160 VAC Emergency buses (l/2R22-S005,6,7) twice per hour.                U the indicated voltage is greater than 3850VAC,            3=    the bus voltages are considered acceptable.
MGR-0002 Rev. 5
 
4.1.4    INFONI the entire shift operating crew    =  RSCORD appropriate log entries of the increased potential for a degraded voltage QR lose of offsite power event.
4.1.5    Notify the Manager of Operations,  the On-site Duty Manager and the On-call Hatch Project Duty Manager.
4.2    Upon notification from System Operating Center that the 230KV bus voltage C        be maintained above normal minimum voltage, QOZU the 4160VAC bus voltagese        be maintained above 38SOVAC, the following action will be taken:
4.2.1    INMTxATh an won* Hour LCON to RZSTODR the 4160VAC Bus voltages to acceptable levels (greater than or equal to 3850VAC).
4.2.2    Notify the Manager of Operations, the On-site Duty Manager, and the On-call Hatch Project Duty Manager.
4.2.3    U the 416OVAC Bus voltages are fnO R.STORZD acceptable levels WAMN one hour, an orderly plant SHUTDOWN will be rINTIATKD with the intent of reaching HOT SHUTDOWN in 6 hours and COLD SHUTDOWN NZ=ZN the following 30 hours. Refer to 73SP-SIP-001-OS and notify the NRC by the EqS (fPX 2000).
MGR-0001 Rev. 1


==3.0 CLASSIFICATION==
LOP Instrumentation 3.3.8.1 3.3  INSTRUMENTATION 3.3.8.1    Loss of Power (LOP)    Instrumentation LCO  3.3.8.1      The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE.                                                   .-. I I
A low voltage condition was sensed on 4160V BUS IE. EOUIPMENT STATUS 4.0 LOCATION: l~l1-P652 PANEL 652-1 5.0 OPERATOR ACTIONS: 5.1 Confirm that voltage is less than 3867 volts on Panel 1111-P652 on 4160V BUS IE Voltmeter.
APPLICABILITY:    MODES 1, 2, and 3, When the associated diesel generator (DG)          is required to be OPERABLE by LCO 3.8.2. *AC Sources -        Shutdown."
5.2 1E voltage is below 3867 volts; notify Georgia Control Center and request operator to raise the voltage on the system to normal.5.3 If voltage on the system cannot be restored, enter 34AB-SIl-OOl-OS, Operation with Degraded System Voltage..6.0 CAUSES: 6.1 System voltage is low
ACTIONS
                                                  .NT        - . .*"  "      U.
------------------------ NOTE----------------------------------
Separate Condition entry is allowed for each channel.
CONDITION                          REQUIRED ACTION            COMPLETION TIME A. One or more channels        A.1        Restore channel to        1 hour inoperable for                          OPERABLE status.
Functions 1 and 2.
B. One or more channels          B.I        Verify voltage on          Once per hour inoperable for                          associated 4.16 kV Function 3.                            bus is ? 3825 V.
C. Required Action and        C.1        Declare associated DG      Immediately associated Completion                  inoperable.
Time not met.
HATCH UNIT 1                                3.3-67                              REVISJO C


==7.0 REFERENCES==
LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)
Lose of Power Inst'iaventetion REQUIRED CNAMMELS          SURVEILLANCE          ALLOWUALE FUNCTION                        PER BUS          REWIIRENENTS              VALUE
: 1. 4.16 kV Emergency Bus Urndervoltage (LOSS of Voltage)
: a. Bus Undervottage                          2            So  3.3.8.1.2  t 2100 V SR  3.3.8.1.3 SA  3.3.8.1.4
: b. Tim Deley                                  2            S8 3.3.8.1.2 S11 3.3.8.1.3    s 6.5 seconds sm 3.3.8.1.4
: 2. 4.16 kV Emargency Bus Undervottage (Degreded Voltage)
: a. Ilu Undervoltage                            2            SR  3.3.8.1.2  x 3280 V SR  3.3.8.1.3 sm  3.3.8.1.4
: b. Time Delay                                  2            Sa 3.3.8.1.2 s8 3.3.8.1.3    A 21.5 seconds SR 3.3.8.1.4
: 3. 4.16 kV Emergency SuM Undervottage (Am* Ic ation)
: a. Ilu Undervoltege                            1              SR 3.3.8.1.1  i 3825 V SR 3.3.8.1.2 SR 3.3.8.1.3 S1 3.3.6.1.4 SR 3.3.8.1.2    s 60 seconds
: b. Time Oelay                                                SR 3.3.8.1.3 SA 3.3.8.1.4 HATCH UNIT 1                                      3.3-68A                                    REVISION C


8.0 TECH. SPEC./LCO:
I UNITED STATES oNUCLEAR C                     REGULATORY COMMISSION WASHINGTON, D.C. 2W.omOi1 February 23, 1995 Mr. J. T. Beckham, Jr.
7.1 H-13412, Elementary Diagrams Diesel 8.1 3/4.9, Electrical Power Systems Gen IA DEPT. MGR DATE _ 34AR-652-122-IS IRev. 4 MGR-0048 Rev. I 21DC-DCX-001-OS GEORGIA POWER COMPANY DOCUMENT TYPE: PAGE I OF 2 PLANT E.I. MATCH[ ABNORMAL OPERATING PROCEDURE TITLE. DOCUMENT NUMBER: REVISION NO: OPERATION WITH DEGRADED SYSTEM VOLTAGE 34AB-Sll-001-os I EXPIRATION DATE: APPROVALS:
Vice President - Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201
MARKUP APPROVED BY: EFFECTIVE DEPARTMENT MANAGER J.C. LEWIS DATE 3-19-93 DATE: N/A GMNP/AGM-PO/AGK-PS N/A
___ __ _..r- r, -v,- .r" 1 S':?,~ SO ?V~ SUPORT r..-jQ11N1NT CONTROL I 1.0 CONDITIONS Normal minmum voltage with either Unit in modem 1, 2, or 3 in 233KV. Normal minimum voltage with both units in COLD SHUTDOWN, REFUEL or with Fuel Ramved is 225KV.1.1 The System Operating Center (Birmingham) ham notified the Superintendent On Shift that the Offmite Distribution System is in jeopardy of ZM being able to maintain normal minimum voltage at the 230KV bum.1.2 The System Operating Center has notified the Superintendent On Shift that the 230KV Bus voltage C be maintained above normal minimum voltage.2.0 AUTOMATIC ACTIONS None 3.0 I!4EDIATE OPERATOR ACTIONS N/A -not applicable to this procedure.
4.0 SUBSEOUENT OPERATOR ACTIONS 4.1 Upon notification from System Operating Center that the Offmite Distribution System is one contingency (event) away from being unable to maintain normal minimum voltage on the 230KV bus, the following action. are to be taken: 4 .1.1 RETURN inoperable Emergency Diesel Generators to operable status as soon an possible.4.1.2 NO maintenance QS surveillance is to be initiated an critical comonents of the on-mite electrical distribution system AM those in process are to be RESTORED to normal an TZiIMRTED as moow am possible.4.1.3 ASSIGN an operator to monitor the voltage indicators for the mix 4160 VAC Emergency buses (l/2R22-S005,6,7) twice per hour. U the indicated voltage is greater than 3850VAC, 3= the bus voltages are considered acceptable.
MGR-0002 Rev. 5 4.1.4 INFONI the entire shift operating crew = RSCORD appropriate log entries of the increased potential for a degraded voltage QR lose of offsite power event.4.1.5 Notify the Manager of Operations, the On-site Duty Manager and the On-call Hatch Project Duty Manager.4.2 Upon notification from System Operating Center that the 230KV bus voltage C be maintained above normal minimum voltage, QO ZU the 4160VAC bus voltages e be maintained above 38SOVAC, the following action will be taken: 4.2.1 INMTxATh an won* Hour LCON to RZSTODR the 4160VAC Bus voltages to acceptable levels (greater than or equal to 3850VAC).4.2.2 Notify the Manager of Operations, the On-site Duty Manager, and the On-call Hatch Project Duty Manager.4.2.3 U the 416OVAC Bus voltages are fnO R.STORZD acceptable levels WAMN one hour, an orderly plant SHUTDOWN will be rINTIATKD with the intent of reaching HOT SHUTDOWN in 6 hours and COLD SHUTDOWN NZ=ZN the following 30 hours. Refer to 73SP-SIP-001-OS and notify the NRC by the EqS (fPX 2000).MGR-0001 Rev. 1 LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO 3.3.8.1 APPLICABILITY:
The LOP instrumentation for each Function in Table 3.3.8.1-1 I shall be OPERABLE.
.-. I MODES 1, 2, and 3, When the associated diesel generator (DG) is required to be OPERABLE by LCO 3.8.2. *AC Sources -Shutdown." ACTIONS... ... ... .... .NT -' -' -...U. "------------------------
NOTE----------------------------------
Separate Condition entry is allowed for each channel.CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Restore channel to 1 hour inoperable for OPERABLE status.Functions 1 and 2.B. One or more channels B.I Verify voltage on Once per hour inoperable for associated 4.16 kV Function 3. bus is ? 3825 V.C. Required Action and C.1 Declare associated DG Immediately associated Completion inoperable.
Time not met.HATCH UNIT 1 3.3-67 REVISJO C LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)Lose of Power Inst'iaventetion REQUIRED CNAMMELS SURVEILLANCE ALLOWUALE FUNCTION PER BUS REWIIRENENTS VALUE 1. 4.16 kV Emergency Bus Urndervoltage (LOSS of Voltage)a. Bus Undervottage 2 So 3.3.8.1.2 t 2100 V SR 3.3.8.1.3 SA 3.3.8.1.4 b. Tim Deley 2 S8 3.3.8.1.2 S11 3.3.8.1.3 s 6.5 seconds sm 3.3.8.1.4 2. 4.16 kV Emargency Bus Undervottage (Degreded Voltage)a. Ilu Undervoltage 2 SR 3.3.8.1.2 x 3280 V SR 3.3.8.1.3 sm 3.3.8.1.4 b. Time Delay 2 Sa 3.3.8.1.2 s8 3.3.8.1.3 A 21.5 seconds SR 3.3.8.1.4 3. 4.16 kV Emergency SuM UndervottageIc ation)a. Ilu Undervoltege 1 SR 3.3.8.1.1 i 3825 V SR 3.3.8.1.2 SR 3.3.8.1.3 S1 3.3.6.1.4 SR 3.3.8.1.2 s 60 seconds b. Time Oelay SR 3.3.8.1.3 SA 3.3.8.1.4 HATCH UNIT 1 3.3-68A REVISION C I UNITED STATES C oNUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2W.omOi1 February 23, 1995 Mr. J. T. Beckham, Jr.Vice President  
-Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201  


==SUBJECT:==
==SUBJECT:==
Line 889: Line 1,510:


==Dear Mr. Beckham:==
==Dear Mr. Beckham:==
By letter dated July 1, 1994, you reqgested approval of a deviation from the current NRC staff position on degraded grid protection.
 
This letter was a supplement to your November 22, 1993, letter which contained a description of your degraded grid protection system.The staff has reviewed the above submittals and the information provided during our meetings on August 6, 1992, November 16, 1993, and December 7, 1994. Based on its review, the staff finds that your approach is acceptable as documented in the enclosed Safety Evaluation.
By letter dated July 1, 1994, you reqgested approval of a deviation from the current NRC staff position on degraded grid protection. This letter was a supplement to your November 22, 1993, letter which contained a description of your degraded grid protection system.
This completes our action with respect to the above TAC. If you have any questions related to this matter, please contact me at (301) 415-1496.Sincerely, Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects -I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366  
The staff has reviewed the above submittals and the information provided during our meetings on August 6, 1992, November 16, 1993, and December 7, 1994. Based on its review, the staff finds that your approach is acceptable as documented in the enclosed Safety Evaluation. This completes our action with respect to the above TAC. If you have any questions related to this matter, please contact me at (301) 415-1496.
Sincerely, Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366


==Enclosure:==
==Enclosure:==
Sfety Evaluation cc w/encl:  See next page CL    I HATCH LICENSING &ENGNG
Mr. J. T. Beckhm, Jr.
Georgia Power Company              Edwin 1. Hatch Nuclear Plant cc:                                Mr. Ernie Toupin Mr. Ernest L. Blake, Jr.            Manager of Nuclear Operations Shaw, Pittman, Potts and Trowbridge Oglethorpe Power Corporation 2300 N Street, NW.                  2100 East Exchange Place Washington, DC 20037                Tucker, Georgia 30085-1349 Mr. 0. M. Crowe                    Charles A. Patrizia, Esquire Manager Licensing - Hatch          Paul, Hastings, Janofsky & Walker Georgia Power Company              12th Floor P. 0. Box 1295                      1050 Connecticut Avenue, NW.
Birmingham, Alabama 35201          Washington, DC 20036 Mr. L. Sumner                      Mr. Jack D. Woodard General Manager, Nuclear Plant      Senior Vice President -
Georgia Power Company                  Nuclear Operations Route 1, Box 439                    Georgia Power Company Baxley, Georgia 31513              P. 0. Box 1295 Birmingham, Alabama 35201 Resident Inspector U.S. Nuclear Regulatory Commission  Chairman Route 1, Box 725                    Appling County Commissioners Baxley, Georgia 31513              County Courthouse Baxley, Georgia 31513 Regional Administrator, Region II U.S. Nuclear Regulatory Commission 101 Marietta Street, NW. Suite 2900 Atlanta, Georgia 30323 Mr. Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW.
Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334
UNITED STATES 0          NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2056-6001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION DEGRADED GRID VOLTAGE RELAY SETPOINTS GEORGIA POWER COMPANY. ET AL.
EDWIN I. HATCH NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366 I. INTRODUCTION Georgia Power Company, et al. (GPC or the licensee) is proposing to deviate from the current NRC staff guidance provided in Generic Letters (GLs) dated 1977 and 1979 with respect to sustained degraded voltage conditions of the offsite power source and the adequacy of the station electric distribution system voltages (Reference 1). The GLs provided supplemental guidance to help ensure that all plants' electrical systems meet a staff interpretation of General Design Criterion (GDC) 17 regarding degraded'voltages.
The staff had concluded in 1982 that Hatch met the positions in the GLs (Reference 2). As part of the design approach, Hatch included a second level of degraded undervoltage protection with a nominal trip setpoint of 78.8% of bus voltage with a time delay of 21.5 seconds. CV-7 relays were used which have inverse time characteristics. Subsequently, an Electrical Distribution System Functional Inspection (EDSFI) determined that the voltage calculations done to support the setpoints were not adequate. Hatch was required to update the voltage calculations and the results indicated that the setpoint for the degraded grid protection should be raised to assure at least 91% voltage at the 4160 volt safety buses (Reference 3). Hatch investigated the feasibility of raising the setpoints at which automatic action would occur and concluded that the changes would involve new equipment and would be very costly.
Furthermore, they believed that raising the setpoint would not significantly improve safety and could lead to unwanted plant trips. As a result, they proposed an interim approach, which relied on maintaining the 230 kV switchyard voltage between 101.3% and 104.9% and included alarm relays set at a higher voltage level (about 92%) and associated manual actions. The staff approved the interim approach but requested that the licensee continue to investigate the matter. The licensee is now proposing the interim approach as the final resolution to meet the GLs.
Specifically, the licensee is proposing to maintain the existing setpoints for their automatic degraded voltage protection scheme and to rely on anticipatory alarms set at 92% and operator actions to provide protection. They believe that this approach provides the necessary protection and that the cost of changing equipment is not justified based on their conclusion that such changes would not improve safety.
By maintaining their Interim approach and not raising the setpoint for automatic action, it
                  ,                      t        rt4vn1eN, valteve94--p r                              .... ,'
                                                  ,,-rmt,            "6-Wpvtia d otv,    This is considered a deviation from the GL positions, and therefore, the licensee has specifically requested that the staff approve the deviation.
In support of the deviation there have been a number of meetings and letters as listed below:
: 1. Meeting summary dated August 16, 1991, for the August 6, 1991, meeting.
: 2. Meeting summary dated December 21, 1992, for the November 16, 1992, meeting.
: 3. Letter from Georgia Power to NRC dated November 22, 1993.
: 4. Letter from Georgia Power to NRC dated July 1, 1994.
: 5. Meeting summary dated January 10, 1995, for the December 7, 1994, meeting.
II. EVALUATION The licensee's approach is based on their understanding of the events which led to issuance of the GLs and potential events which might challenge the Hatch facility. The GLs were prompted by events at Millstone One and Arkansas Nuclear One which heightened concerns for potential sustained degraded grid voltages and in plant voltage problems due to potential severe loading conditions during accidents.
The specific sequence of events which would require that the voltage setpoints be raised involves the simultaneous existence of a degraded offsite power source and a loss-of-coolant accident (LOCA). A LOCA puts the heaviest demand on the safety buses and if it would occur during degraded grid voltage conditions, some safety equipment might not receive sufficient voltage to perform their function. Among other requirements, the GLs required that the occurrence of a degraded offsite voltage should be sensed, and then an automatic transfer to the emergency diesel generators (EDGs) should take place. For the sequence of events of a degraded grid voltage and a LOCA, the licensee has concluded that the likelihood of such simultaneous events is extremely low. This is based on their existing grid operation coupled with the low likelihood of a LOCA.
Plant Hatch is part of the Southern electric grid system which is a member of the Southeastern Electric Reliability Council. The Southern electric system employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators of the Southern electric grid ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse effects from postulated grid system failures. Based on the contingency analysis results, system operators configure the offsite power system such that a worst-case postulated failure can occur without adversely affecting the minimum required voltage.
If the 230 kV system at Hatch were to fall below the current minimum expected value of 101.3%, the switchyard design and offsite power system design allows system operators to quickly mitigate such a dynamic voltage excursion. The following actions would be performed by system operators:
* System operators receive low voltage alarm.
"      System operators notify the control room at Plant Hatch.
"      The 162 MVAR capacitor bank on the 230 kV line is switched on (if off).
"      The 150 MVAR shunt reactors on the 500 kV line are turned off (if        on).
"      Capacitor banks in the surrounding area are turned on (if      off).
* Combustion turbines at Plant McManus are placed in service.
These actions are normally capable of improving the 230 kW voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators would take the following actions:
"      Out of service elements are brought back on line.
"      System load (external or internal) is reduced.
Therefore, because of the above outlined offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion is more likely. For a dynamic voltage excursion, GPC believes that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.
E** e!ntors,'f Soutbn electric grid fail t Jmrove the 23Q kV        I        ,  1R has issoed an Operatinj Order at P1l  aW      which l              s*e* f'9 actions to be taken if the grid system operators are in Je~~d'd~onot Wntatinng the Hatch voltages within the ,required operatdng qme. The actions consist of restoring any inoperable EDGs, limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on tIL.ix 4160 volt safety-related buses, and informing pTant management.        Nov -Fu4jp__      . MU-_._
n      s tet4et-to be performed tP the 460W volt ellsentil Nes al beelqw tJt h      :MW*,,,      ee,      e v9"ge.,      These a%3.tie it c aidA*Alai*    t* Wh        L    ting..Condition of wneent, and an 9W Yp70      '.ht-low    ifWINUPS            e .Th actions specified in the Operating Order have been incorporated into abnormal operating procedure 34AB-SII-001-OS, "Operation With Degraded System Voltage."
This procedure would also be entered on receiving the low voltage alarms on the 4160 volt buses. Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.
Therefore, the licensee concludes that, because of the elements in place on the Southern electric grid and at Plant Hatch, it would be a very rare event for the offsite voltage at Hatch to be below 101.3% during a postulated independent LOCA (from their RPE the estimated occurrence of a LOCA Is 2.61 x 10-4 for Hatch).
In response to NRC staff concerns, the licensee also investigated other potentially more likely events, and has concluded that the alarms and procedures along with the plant's inherent response capabilities provide sufficient protection.
: 1. Sustained degraded grid conditions (no LOCA or plant trip)
If the voltages on the offsite system were to degrade to unacceptable levels for a sustained period of time, the plant would be notified by the Southern System load dispatcher and in addition the plant alarms would alert the operators to the condition. Procedures would be implemented to restore voltages in one hour or start an orderly shutdown. By not raising the setpolnt at which automatic action would occur, some potential for unnecessary automatic unit trips could be avoided.
: 2. Dynamic voltage excursion (no LOCA or plant trip)
If the voltages on the offsite system were to degrade to the unacceptable level for a short period of time (on the order of minutes),
the plant would be notified by the Southern System load dispatcher.
Procedures would be implemented to restore the voltages. By not raising the setpoint at which automatic action would occur, unnecessary unit trips might be avoided. As noted by the licensee, an event of this nature occurred on Sunday, March 14, 1993. The licensee's post-event analysis concluded that this event supported its integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation. Details of the event and the licensee's analysis are provided in the appendix to this evaluation.
: 3. Sustained degraded grid conditions or a dynamic voltage excursion with Hatch units tripping (no LOCA)
If a plant trip occurred during a grid problem (which could reasonably be expected to occur due to problems related to the equipment exposed to the degraded voltages, or because the tripping of the Hatch units was part of the problem leading to the degraded grid voltage) operator response to correct the voltages might not be quick enough, and therefore, damage to some ac equipment could occur. In this situation, the licensee has analyzed their facility and concluded that equipment not exposed to the ac voltage problems (because it is operating on dc-backed sources or is not operating and, therefore, free from potential damage),


Sfety Evaluation cc w/encl: See next page C L I HATCH LICENSING
such as reactor core isolation cooling (RCIC) and high pressure coolant injection (HPCI) would be available to safely shut the plant down. This same kind of analysis was done as part of their Station Blackout analysis.
& ENGNG Mr. J. T. Beckhm, Jr.Georgia Power Company cc: Mr. Ernest L. Blake, Jr.Shaw, Pittman, Potts and Trowbridge 2300 N Street, NW.Washington, DC 20037 Mr. 0. M. Crowe Manager Licensing
: 4. Sustained degraded grid conditions or dynamic voltage excursion with Hatch units tripping and then a stuck open relief valve (LOCA)
-Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201 Mr. L. Sumner General Manager, Nuclear Plant Georgia Power Company Route 1, Box 439 Baxley, Georgia 31513 Resident Inspector U.S. Nuclear Regulatory Commission Route 1, Box 725 Baxley, Georgia 31513 Regional Administrator, Region II U.S. Nuclear Regulatory Commission 101 Marietta Street, NW. Suite 2900 Atlanta, Georgia 30323 Mr. Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW.Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334 Edwin 1. Hatch Nuclear Plant Mr. Ernie Toupin Manager of Nuclear Operations Oglethorpe Power Corporation 2100 East Exchange Place Tucker, Georgia 30085-1349 Charles A. Patrizia, Esquire Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW.Washington, DC 20036 Mr. Jack D. Woodard Senior Vice President
This event could be the most probable sequence involving a degraded grid and LOCA. Because the plant response would be the same (e.g., RCIC, HPCI) the same conclusions as the above event sequence would also apply.
-Nuclear Operations Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201 Chairman Appling County Commissioners County Courthouse Baxley, Georgia 31513 UNITED STATES 0 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2056-6001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION DEGRADED GRID VOLTAGE RELAY SETPOINTS GEORGIA POWER COMPANY. ET AL.EDWIN I. HATCH NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366 I. INTRODUCTION Georgia Power Company, et al. (GPC or the licensee) is proposing to deviate from the current NRC staff guidance provided in Generic Letters (GLs) dated 1977 and 1979 with respect to sustained degraded voltage conditions of the offsite power source and the adequacy of the station electric distribution system voltages (Reference 1). The GLs provided supplemental guidance to help ensure that all plants' electrical systems meet a staff interpretation of General Design Criterion (GDC) 17 regarding degraded'voltages.
The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:
The staff had concluded in 1982 that Hatch met the positions in the GLs (Reference 2). As part of the design approach, Hatch included a second level of degraded undervoltage protection with a nominal trip setpoint of 78.8% of bus voltage with a time delay of 21.5 seconds. CV-7 relays were used which have inverse time characteristics.
-I'l   The degraded voltage alarm relays should be included in the plant Technical Specifications along with the degraded voltage relays which initiate automatic actions.
Subsequently, an Electrical Distribution System Functional Inspection (EDSFI) determined that the voltage calculations done to support the setpoints were not adequate.
1     The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.
Hatch was required to update the voltage calculations and the results indicated that the setpoint for the degraded grid protection should be raised to assure at least 91% voltage at the 4160 volt safety buses (Reference 3). Hatch investigated the feasibility of raising the setpoints at which automatic action would occur and concluded that the changes would involve new equipment and would be very costly.Furthermore, they believed that raising the setpoint would not significantly improve safety and could lead to unwanted plant trips. As a result, they proposed an interim approach, which relied on maintaining the 230 kV switchyard voltage between 101.3% and 104.9% and included alarm relays set at a higher voltage level (about 92%) and associated manual actions. The staff approved the interim approach but requested that the licensee continue to investigate the matter. The licensee is now proposing the interim approach as the final resolution to meet the GLs.Specifically, the licensee is proposing to maintain the existing setpoints for their automatic degraded voltage protection scheme and to rely on anticipatory alarms set at 92% and operator actions to provide protection.
They believe that this approach provides the necessary protection and that the cost of changing equipment is not justified based on their conclusion that such changes would not improve safety. By maintaining their Interim approach and not raising the setpoint for automatic action, it , t rt4vn1eN, valteve94--p r .... ,' ,,-rmt, "6-Wpvtia d otv, This is considered a deviation from the GL positions, and therefore, the licensee has specifically requested that the staff approve the deviation.
In support of the deviation there have been a number of meetings and letters as listed below: 1. Meeting summary dated August 16, 1991, for the August 6, 1991, meeting.2. Meeting summary dated December 21, 1992, for the November 16, 1992, meeting.3. Letter from Georgia Power to NRC dated November 22, 1993.4. Letter from Georgia Power to NRC dated July 1, 1994.5. Meeting summary dated January 10, 1995, for the December 7, 1994, meeting.II. EVALUATION The licensee's approach is based on their understanding of the events which led to issuance of the GLs and potential events which might challenge the Hatch facility.
The GLs were prompted by events at Millstone One and Arkansas Nuclear One which heightened concerns for potential sustained degraded grid voltages and in plant voltage problems due to potential severe loading conditions during accidents.
The specific sequence of events which would require that the voltage setpoints be raised involves the simultaneous existence of a degraded offsite power source and a loss-of-coolant accident (LOCA). A LOCA puts the heaviest demand on the safety buses and if it would occur during degraded grid voltage conditions, some safety equipment might not receive sufficient voltage to perform their function.
Among other requirements, the GLs required that the occurrence of a degraded offsite voltage should be sensed, and then an automatic transfer to the emergency diesel generators (EDGs) should take place. For the sequence of events of a degraded grid voltage and a LOCA, the licensee has concluded that the likelihood of such simultaneous events is extremely low. This is based on their existing grid operation coupled with the low likelihood of a LOCA.Plant Hatch is part of the Southern electric grid system which is a member of the Southeastern Electric Reliability Council. The Southern electric system employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators of the Southern electric grid ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse effects from postulated grid system failures.
Based on the contingency analysis results, system operators configure the offsite power system such that a worst-case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system at Hatch were to fall below the current minimum expected value of 101.3%, the switchyard design and offsite power system design allows system operators to quickly mitigate such a dynamic voltage excursion.
The following actions would be performed by system operators:
* System operators receive low voltage alarm." System operators notify the control room at Plant Hatch." The 162 MVAR capacitor bank on the 230 kV line is switched on (if off)." The 150 MVAR shunt reactors on the 500 kV line are turned off (if on)." Capacitor banks in the surrounding area are turned on (if off).* Combustion turbines at Plant McManus are placed in service.These actions are normally capable of improving the 230 kW voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators would take the following actions: " Out of service elements are brought back on line." System load (external or internal) is reduced.Therefore, because of the above outlined offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion is more likely. For a dynamic voltage excursion, GPC believes that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.e!ntors,'f Soutbn electric grid fail t Jmrove the 23Q kV , I 1R has issoed an Operatinj Order at P1 l aW which l f'9 actions to be taken if the grid system operators are in Je~~d'd~onot Wntatinng the Hatch voltages within the ,required operatdng qme. The actions consist of restoring any inoperable EDGs, limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on tIL.ix 4160 volt safety-related buses, and informing pTant management.
Nov -Fu4jp__ .MU-_._ n s tet4et-to be performed tP the 460W volt ellsentil Nes al beelqw tJt h ee, e v9"ge., These a%3.tie c it Wh L ting.. Condition of wneent, and an 9W Yp70 '.ht-low ifWINUPS e .Th actions specified in the Operating Order have been incorporated into abnormal operating procedure 34AB-SII-001-OS, "Operation With Degraded System Voltage." This procedure would also be entered on receiving the low voltage alarms on the 4160 volt buses. Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures. Therefore, the licensee concludes that, because of the elements in place on the Southern electric grid and at Plant Hatch, it would be a very rare event for the offsite voltage at Hatch to be below 101.3% during a postulated independent LOCA (from their RPE the estimated occurrence of a LOCA Is 2.61 x 10-4 for Hatch).In response to NRC staff concerns, the licensee also investigated other potentially more likely events, and has concluded that the alarms and procedures along with the plant's inherent response capabilities provide sufficient protection.
: 1. Sustained degraded grid conditions (no LOCA or plant trip)If the voltages on the offsite system were to degrade to unacceptable levels for a sustained period of time, the plant would be notified by the Southern System load dispatcher and in addition the plant alarms would alert the operators to the condition.
Procedures would be implemented to restore voltages in one hour or start an orderly shutdown.
By not raising the setpolnt at which automatic action would occur, some potential for unnecessary automatic unit trips could be avoided.2. Dynamic voltage excursion (no LOCA or plant trip)If the voltages on the offsite system were to degrade to the unacceptable level for a short period of time (on the order of minutes), the plant would be notified by the Southern System load dispatcher.
Procedures would be implemented to restore the voltages.
By not raising the setpoint at which automatic action would occur, unnecessary unit trips might be avoided. As noted by the licensee, an event of this nature occurred on Sunday, March 14, 1993. The licensee's post-event analysis concluded that this event supported its integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation.
Details of the event and the licensee's analysis are provided in the appendix to this evaluation.
: 3. Sustained degraded grid conditions or a dynamic voltage excursion with Hatch units tripping (no LOCA)If a plant trip occurred during a grid problem (which could reasonably be expected to occur due to problems related to the equipment exposed to the degraded voltages, or because the tripping of the Hatch units was part of the problem leading to the degraded grid voltage) operator response to correct the voltages might not be quick enough, and therefore, damage to some ac equipment could occur. In this situation, the licensee has analyzed their facility and concluded that equipment not exposed to the ac voltage problems (because it is operating on dc-backed sources or is not operating and, therefore, free from potential damage),  such as reactor core isolation cooling (RCIC) and high pressure coolant injection (HPCI) would be available to safely shut the plant down. This same kind of analysis was done as part of their Station Blackout analysis.4. Sustained degraded grid conditions or dynamic voltage excursion with Hatch units tripping and then a stuck open relief valve (LOCA)This event could be the most probable sequence involving a degraded grid and LOCA. Because the plant response would be the same (e.g., RCIC, HPCI) the same conclusions as the above event sequence would also apply.The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:-I'l The degraded voltage alarm relays should be included in the plant Technical Specifications along with the degraded voltage relays which initiate automatic actions.1 The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.
The licensee has agreed to these added conditions.
The licensee has agreed to these added conditions.
W IerW~ approac Awiyit&#xfd;~ -o-ta+/-~b~k,.nff sttr -and
W       IerW~   approac                                 Awiyit&#xfd;~ sttr -and
' 6t+t e,' e&#xa2;c1 w O W e eapvbhiitt of p~444g.p~wer foo4ed-v eufe Iopaet in.*4Ac ith GOC 11-Of W-GFR III. CONCLUSION Based on its review, the staff finds that the requested deviation from the Generic Letters is acceptable because of the added design features and the compensatory measures at Hatch as discussed in the above Safety Evaluation.
                                                                  -o-ta+/-~b~k,.nff
Principal Contributors:
*4.5'SVW08I                        ' e&#xa2;c1 e,' 6t+t w W   eO eapvbhiitt of p~444g.p~wer foo4ed-v eufeIopaet                  in.*4Ac       ith GOC 11-Of W-GFR III. CONCLUSION Based on its review, the staff finds that the requested deviation from the Generic Letters is acceptable because of the added design features and the compensatory measures at Hatch as discussed in the above Safety Evaluation.
D. Thatcher N. Trehan Date: February 23, 1995 HFREENCES 1. a. June 2, 1977, NRC Generic Letter (Staff Positions) regarding the onsite emergency power systems.b. August 8, 1979, NRC Generic Letter regarding the wAdequacy of Station Electric Distribution Systems Voltages.*
Principal Contributors:   D. Thatcher N. Trehan Date:   February   23, 1995
: 2. a. April 5, 1982, NRC Staff Safety Evaluation regarding the adequacy of electric distribution system voltages at Hatch Units 1 and 2.b. May 6, 1982, NRC Staff Safety Evaluation regarding degraded grid Technical Specifications.
 
HFREENCES
: 1. a. June 2, 1977, NRC Generic Letter (Staff Positions) regarding the onsite emergency power systems.
: b. August 8, 1979, NRC Generic Letter regarding the wAdequacy of Station Electric Distribution Systems Voltages.*
: 2. a. April 5, 1982, NRC Staff Safety Evaluation regarding the adequacy of electric distribution system voltages at Hatch Units 1 and 2.
: b. May 6, 1982, NRC Staff Safety Evaluation regarding degraded grid Technical Specifications.
: 3. August 22, 1991, Electrical Distribution System Functional Inspection at Hatch, NRC Inspection Report No. 91-202.
: 3. August 22, 1991, Electrical Distribution System Functional Inspection at Hatch, NRC Inspection Report No. 91-202.
APPENDIX TEMPORARY VOLTAGE EXCURSION EVENT AT PLANT HATCH A temporary voltage excursion event occurred at Plant Hatch on Sunday, March 14, 1993. During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks.
 
During this time, specifically on March 14, 1993, at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent).
APPENDIX TEMPORARY VOLTAGE EXCURSION EVENT AT PLANT HATCH A temporary voltage excursion event occurred at Plant Hatch on Sunday, March 14, 1993. During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993, at 10:04 a.m.,
At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was-informed of the situation and confirmed that the Florida System was bringing up generation to stabilize the power flow from the Southern.System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.
Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m.,
The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.Georgia Power's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation.
the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was-informed of the situation and confirmed that the Florida System was bringing up generation to stabilize the power flow from the Southern.System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery. The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.
The actual effect or drop in voltage on the 4160 volt buses at Plant Hatch was not available, but no adverse effects were noted at the plant.However, as part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room.Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.
Georgia Power's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt buses at Plant Hatch was not available, but no adverse effects were noted at the plant.
Technically, both units should have been in a one hour LCO.The notification did not occur as system operations had concluded that the system was not in Jeopardy; the voltage excursion was quickly being restored.Corrective actions were taken to clarify this requirement and assure proper communications.
However, as part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room.
4-2-The licensee concluded that this event demonstrated that the degraded grid protection for Plant Hatch is consistent with GPC's objectives." The plant was adequately protected from an undervoltage condition as no adverse effects were evident." The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted." The situation was not further exacerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.a If the setpoint for the degraded grid relays had been raised, a trip of Unit 1 probably would not have occurred for this specific event.However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift. Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.This led the licensee to conclude that the actual event supported GPC's integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation.
Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored. Technically, both units should have been in a one hour LCO.
In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offslte power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been Increased.  
The notification did not occur as system operations had concluded that the system was not in Jeopardy; the voltage excursion was quickly being restored.
.* oo~l,, r~.,..r yTIO,*&#xb6;if'.
Corrective actions were taken to clarify this requirement and assure proper communications.
Georgia Power C.vgrpany 40 Inverness Center Parkway* PgsOttice Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 a. T. 5" aiJr. Georgia Power Vice Pesident -Nuclear Hatch Project the sOhew electrc system July 1, 1994 Docket Nos. 50-321 HL4586 50-366 TAC No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1. Hatch Nuclear Plant Degmaded Grid Protection Gentlemen:
 
Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions.
4 The licensee concluded that this event demonstrated that the degraded grid protection for Plant Hatch is consistent with GPC's objectives.
By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.
  "     The plant was adequately protected from an undervoltage condition as no adverse effects were evident.
The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.  
  "     The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.
'-,orgla Power A U.S. Nuclear Regulatory Commission Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the off'ite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to ihe initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-1 of the Unit I and Unit 2 Technical Specifications, respectively.
  "     The situation was not further exacerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts.   (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.
GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband.
a     If the setpoint for the degraded grid relays had been raised, a trip of Unit 1 probably would not have occurred for this specific event.
Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement.
However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift. Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.
If voltages are not restored within one hour, a plant shutdown is then initiated.
This led the licensee to conclude that the actual event supported GPC's integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation.
F' orgia Pwer A U.S. Nuclear Regulatory Commission Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into ths Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications.
In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offslte power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been Increased.
Accordingly, the limiting condition of operation (LCO) will require the degraded grid Wjarms to be operable in modes 1, 2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable.
 
Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded.
                      . yTIO,*&#xb6;if'.
GPC has evaluated this request to raise the alarm setpoints to 97 percent of 4160 volts and determined that it is not feasible nor required.
Georgia Power C.vgrpany
The basis for this conclusion is as follows: The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required.
* oo~l,,            r~.,..r
As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.
* 40 Inverness Center Parkway
As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.  
* PgsOttice Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279
'orgia PowerA U.S. Nuclear Regulatory Commission Page Four July 1, 1994*The current alarm setpoints of approximately 92 to 93 percent of .4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions.
: a. T.5"       aiJr.                                                                 Georgia Power Vice Pesident - Nuclear Hatch Project                                                                   the sOhew electrc system July 1, 1994 Docket Nos. 50-321                                                                     HL4586 50-366 TAC No.           80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1.Hatch Nuclear Plant Degmaded Grid Protection Gentlemen:
The current alarm setpoint values signify that adequate voltage is available for normal operations.
Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.
Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-001 -OS, "Operation With Degraded System Voltage" if the voltage cannot be restored.
The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.
Procedure 34AB-Sl 1-001-OS directs operators to initiate a"one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation.
 
An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers.
'-,orgla Power   A U.S. Nuclear Regulatory Commission                                                 Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.
From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.
GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the off'ite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to ihe initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-1 of the Unit I and Unit 2 Technical Specifications, respectively.
Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint.
GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband. Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement. If voltages are not restored within one hour, a plant shutdown is then initiated.
Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation.
 
As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations.
F' orgia Pwer A U.S. Nuclear Regulatory Commission                                             Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into ths Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications. Accordingly, the limiting condition of operation (LCO) will require the degraded grid Wjarms to be operable in modes 1,2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable. Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.
GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.  
Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded. GPC has evaluated this request to raise the alarm setpoints to 97 percent of 4160 volts and determined that it is not feasible nor required. The basis for this conclusion is as follows:
~,'orgia PbwerA U.S. Nuclear Regulatory Commission July 1, 1994 Page Five Should you have any questions in this regard, please contact this office.Sincerely, L .T. Beckliarn.
The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required. As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.
Jr.JKB/cr cc: Georiga Power CorM~v Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear Regulator Commission, Washingon, D.C.Mr. K. Jabbour, Licensing Project Manager -Hatch U.S. Nuclear Regulator Commission.
As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.
Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector  
 
-Hatch Gworg~Powor Comparvy 40 Invunm Cente Palway a Post Office Box 1295 Birmingham, Alabama 35201 Telephwwi 205 877-7279 J. T. Georgia Power Vim President
'orgia PowerA U.S. Nuclear Regulatory Commission                                             Page Four July 1, 1994
* Nuclear Hatch Project f~t soumnern evc:',,; ." November 22, 1993 Docket Nos. 50-321 HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
        *The current alarm setpoints of approximately 92 to 93 percent of .4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions. The current alarm setpoint values signify that adequate voltage is available for normal operations. Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-001 -OS, "Operation With Degraded System Voltage" if the voltage cannot be restored. Procedure 34AB-Sl 1-001-OS directs operators to initiate a "one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation. An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers. From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.
On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions.
Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint. Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.
The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure.
Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation.             As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations. GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.
Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.
 
Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).
                                                        ~,
Qargia Pbwer U.S. Nuclear Regulatory Commission ,Page Two November 22, 1993.Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.
'orgia PbwerA U.S. Nuclear Regulatory Commission                                       Page Five July 1, 1994 Should you have any questions in this regard, please contact this office.
Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased.
Sincerely, L.T.Beckliarn. Jr.
In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required.
JKB/cr cc: GeorigaPowerCorM~v Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. NuclearRegulator Commission, Washingon, D.C.
Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary.
Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Regulator Commission. Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector - Hatch
Consequently, GPC does not consider further actions to be necessary.
 
The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.Sincerely, 6.T. Beckham, Jr.JKB/cr 004440  
Gworg~Powor Comparvy 40 Invunm Cente Palway a
Post Office Box 1295 Birmingham, Alabama 35201 Telephwwi 205 877-7279 J. T.
Vim President
* Nuclear                                                         Georgia Power t
Hatch Project                                                                 f~ soumnern evc:',,; ."
November 22,       1993 Docket Nos.       50-321                                                         HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:
On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.
During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.
Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.
As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).
 
Qargia Pbwer U.S. Nuclear Regulatory Commission                                         ,Page Two November 22,     1993
        .Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.
Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased. In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required. Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary. Consequently, GPC does not consider further actions to be necessary.
The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.
Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.
Sincerely, 6.T. Beckham, Jr.
JKB/cr 004440


==Enclosure:==
==Enclosure:==
Degraded Grid Voltage Protection cc: (See next page.)
Georgia Power  A U.S. Nuclear Regulatory Commission                      Page Three November 22, 1993 cc: GeorgiaPower Comvanv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear ReBuMaLoq Commission. Washingon. D.C.
Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. NuclearRe*,ulator Commission. Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch
Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC) implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided. This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.
Oriin of the Issue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers. An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors. As a result, the control power fuses were blown when the 480 volt motors were signaled to start.
At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.
However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.
HL-4440                                      E-1
PI-'
Enclosure Degraded Grid Voltage Protection In response to the event at Millstone, by letter dated June 2, 1977, the NRC requested GPC to assess the susceptibility of safety related electrical equipment to a sustained voltage degradation of the offsite source. The letter contained positions with which the design of the plant was to be compared. These positions were the precursors to a branch technical position and are as follows:
: 1. "The selection of voltage and time setpoints shall be determined from an analysis of the voltage requirements of the safety related loads at all onsite distribution system levels."
: 2. "The voltage protection shall include coincidence logic to preclude spurious trips of the offsite power sources."
: 3. "The time delay selected shall be based on the following conditions:
: a. The allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analysis."
: b. "The time delay shall minimize the effect of short-duration disturbances from reducing the unavailability of the offsite power source(s)."
: c.  "The allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety systems or components."
: 4. "The voltage monitors shall automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time-delay limits have been exceeded."
: 5. "The voltage monitors shall be designed to satisfy the requirements of IEEE Standard 279-1971.
: 6. "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip setpoints with minimum and maximum limits, and allowable values for the second-level voltage protection monitors."
IHL-4440                                          E-2
Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.
Additional information is contained in GPCs submittals dated September 17, 1976; January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.
GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.
EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts),
certain class 1E loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.
By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function. By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection. GPC concluded that a violation of NRC requirements did not exist based on the following:
HL-4440                                      E-3
Enclosure Degraded Grid Voltage Protection
: 1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.
: 2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained. In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected. At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.
Consequently, tap changes were made for the startup transformers in 1986 and 1987.
Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected 1E system voltages are, generally, slightly higher than the bus voltages submitted in 1980.
: 3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
: 4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible. GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would repreient a marginal to safety improvement. This conclusion is based on the following:
A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone. The Southern electric system employs state-
-L-4440                                        E.4
Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse affects from postulated system failures. Based.on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion. Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes.
      " System operators receive low voltage alarm.
      " System operators notify the control room at Plant Hatch.
      " The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off).
      " The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).
        " Capacitor banks in the surrounding area are turned on (if off).
        " Combustion turbines at Plant McManus are placed in service.
These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:
* Out of service elements are brought back on line.
        " System load (external or internal) is reduced.
Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.
HL-4440                                        E-5
Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs),
limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management. The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored. The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-S11-001-OS, "Operation With Degraded System Voltage."
Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.
This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.
An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.
During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440                                        E-6
Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.
The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.
GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.
As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.
Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion. Corrective actions have been taken to clarify this requirement and assure proper communications.
HL-4440                                        E-7
Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.
0 The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.
* The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.
0    The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.
* If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred. However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.
Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.
The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation. In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductionstblackouts within the Southern Electric and Florida Power service areas would have been increased.
C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable. This conclusion is based on the following:
HL.-4440                                    E-8
Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required. GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.
Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available. Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection. As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications. Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.
GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint. While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440                                      E-9
Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected. Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.
Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved:
" The electrical requirements of safety-related equipment.
* The reliability of the offsite power supply.
* The potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source.
" The extremely low probability of a sustained degraded grid event concurrent with a LOCA.
* The impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event.
As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would fikely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.
HL-4440                                        E-10
ATFACHMENT I EDWIN I. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION
Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution System Description Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.
The GPC system is also designed to connect generating units to the grid at optimum locations. This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.
The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.
The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided inFigure 1.
Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.
The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.
The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.
The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, RHR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.
HL-4440                                            A-I
Attachment I Electrical System Description During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.
During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.
During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.
BL-4440                                          A-2
                                                                                          -)
1" -9950 - UNIT I MI" POE DaSIRrnjllI                                  MIN PmfR DISIIO I'H-2350    - UNIT 2            - .,,,2 FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS - NORMAL OPERATION
ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARMJTRIP RANGES
HYPOTHETICAL ALARM / TRIP RANGES NUEFXPECTED VOLTAGE A    SETPOINT TRIP SETPOINT
                  ?IN REQUnRED VOLTAGE I
ATTACHMENT 3 EDWIN I. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS


Degraded Grid Voltage Protection cc: (See next page.)
PLoant Ha~tch .Unit 1     Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E   DEAD BAND CALC. 92764PG
Georgia Power A U.S. Nuclear Regulatory Commission Page Three November 22, 1993 cc: Georgia Power Comvanv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear ReBuMaLoq Commission.
 
Washingon.
Plant Hatch Unit 1      BusF 97.6 EXP 104.9 103.5 101.3 1~~~~
D. C.Mr. K. Jabbour, Licensing Project Manager -Hatch U.S. Nuclear Commission.
ALARM 88.47 REQ EmDEAD BAND CALC. 92764PG I
Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector
-Hatch Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC)implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided.
This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.
Oriin of the Issue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers.
An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors.
As a result, the control power fuses were blown when the 480 volt motors were signaled to start.At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.HL-4440 E-1 PI-'Enclosure Degraded Grid Voltage Protection In response to the event at Millstone, by letter dated June 2, 1977, the NRC requested GPC to assess the susceptibility of safety related electrical equipment to a sustained voltage degradation of the offsite source. The letter contained positions with which the design of the plant was to be compared.
These positions were the precursors to a branch technical position and are as follows: 1. "The selection of voltage and time setpoints shall be determined from an analysis of the voltage requirements of the safety related loads at all onsite distribution system levels." 2. "The voltage protection shall include coincidence logic to preclude spurious trips of the offsite power sources." 3. "The time delay selected shall be based on the following conditions:
: a. The allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analysis." b. "The time delay shall minimize the effect of short-duration disturbances from reducing the unavailability of the offsite power source(s)." c. "The allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety systems or components." 4. "The voltage monitors shall automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time-delay limits have been exceeded." 5. "The voltage monitors shall be designed to satisfy the requirements of IEEE Standard 279-1971.6. "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip setpoints with minimum and maximum limits, and allowable values for the second-level voltage protection monitors." IHL-4440 E-2 Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.Additional information is contained in GPCs submittals dated September 17, 1976;January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class 1E loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function.
By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection.
GPC concluded that a violation of NRC requirements did not exist based on the following:
HL-4440 E-3 Enclosure Degraded Grid Voltage Protection
: 1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained.
In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected.
At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.Consequently, tap changes were made for the startup transformers in 1986 and 1987.Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected 1E system voltages are, generally, slightly higher than the bus voltages submitted in 1980.3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
: 4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible.
GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would repreient a marginal to safety improvement.
This conclusion is based on the following:
A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone.
The Southern electric system employs state--L-4440 E.4 Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse affects from postulated system failures.
Based.on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion.
Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes." System operators receive low voltage alarm." System operators notify the control room at Plant Hatch." The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off)." The 150 MVAR shunt reactors on the 500 kV line are turned off (if on)." Capacitor banks in the surrounding area are turned on (if off)." Combustion turbines at Plant McManus are placed in service.These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:* Out of service elements are brought back on line." System load (external or internal) is reduced.Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.HL-4440 E-5 Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs), limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management.
The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored.
The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-S11-001-OS, "Operation With Degraded System Voltage." Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.
This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks.
During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440 E-6 Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent).
At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation.
The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion.
Corrective actions have been taken to clarify this requirement and assure proper communications.
HL-4440 E-7 Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.
0 The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.* The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.
0 The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.* If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred.
However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation.
In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductionstblackouts within the Southern Electric and Florida Power service areas would have been increased.
C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable.
This conclusion is based on the following:
HL.-4440 E-8 Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required.
GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.
Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available.
Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection.
As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications.
Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.
GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint.
While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440 E-9 Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected.
Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.
Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved: " The electrical requirements of safety-related equipment.
* The reliability of the offsite power supply.* The potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source." The extremely low probability of a sustained degraded grid event concurrent with a LOCA.* The impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event.As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure.
GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would fikely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.
HL-4440 E-10 ATFACHMENT I EDWIN I. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution


===System Description===
Plant Hatch Unit 1             Bus 0 4.16KV 230KV 104,9                          ", 97.6 EXP 103.5 --
Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.The GPC system is also designed to connect generating units to the grid at optimum locations.
101.3 ALARM 91.4 REQ 91.14 EXP 90.80 RED 88.34 LDEAD      BAND CALC, 92764PG
This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.
The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided inFigure 1.Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, RHR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.
HL-4440 A-I Attachment I Electrical


===System Description===
Plaxnt Ha~tch Unit           Bus   E 97.85 EXP 104.9 103.5 101.3 ALARM 90.73 REO MDEAD BAND CALC. 92763PG}}
During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.
During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.BL-4440 A-2
-)1" -9950 -UNIT I MI" POE DaSIRrnjllI MIN PmfR DISIIO I'H-2350 -UNIT 2 -.,,,2 FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS
-NORMAL OPERATION ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARMJTRIP RANGES HYPOTHETICAL ALARM / TRIP RANGES NUEFXPECTED VOLTAGE A SETPOINT TRIP SETPOINT?IN REQUnRED VOLTAGE I ATTACHMENT 3 EDWIN I. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS PLoant Ha~tch.Unit 1 Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E DEAD BAND CALC. 92764PG Plant Hatch Unit 1 BusF 97.6 EXP 104.9 103.5 101.3 1~~~~ALARM 88.47 REQ EmDEAD BAND CALC. 92764PG I Plant Hatch Unit 1 Bus 0 4.16KV 230KV 104,9 103.5 --101.3 91.14 EXP 90.80 RED", 97.6 EXP ALARM 91.4 REQ 88.34 LDEAD BAND CALC, 92764PG Plaxnt Ha~tch Unit Bus E 97.85 EXP 104.9 103.5 101.3 ALARM 90.73 REO MDEAD BAND CALC. 92763PG}}

Latest revision as of 20:50, 6 February 2020

D. R. Madison Ltr. Edwin I. Hatch, Appeal to the Executive Director of Operations: Backfit and Applicability of Compliance Backfit Exception
ML11335A179
Person / Time
Site: Hatch  Southern Nuclear icon.png
Issue date: 10/28/2011
From: Madison D
Southern Nuclear Operating Co
To: Borchardt R
Document Control Desk, NRC/EDO
References
NL-11-2032
Download: ML11335A179 (191)
v • d • e


Text

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Te: ý 12.57 ,Th-.q7 DEDCM f2-i AO October 28, 2011 SOUTHERN A.

COMPANY Docket Nos.: 50-321 NL-1 1-2032 50-366 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant Appeal to the Executive Director of Operations:

Backfit and Aoolicabilitv of "Comoliance Backfit" Exceotion

Dear Mr. R. William Borchardt,

Southern Nuclear Operating Company (SNC) appeals to the Nuclear Regulatory Commission (NRC) Executive Director of Operations (EDO) the September 29, 2011, determination by the NRC staff that a backfit is necessary at Edwin I.

Hatch Nuclear Plant (HNP) awr4 ilso the staff's application of the "compliance backfit" exception to avoid the requirement for performance of a cost-justified backfit analysis. This letter constitutes SNC's response. to the September 29, 2011 NRC letter. Notwithstanding this appeal, as a matter of policy, SNC is committed to resolving the issue technically.

Key points pertinent to this issue include:

1. In a February 23,1 995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1E (safety-related) electrical equipment in the event of degraded voltage conditions. It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable. In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995. SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.
2. On May 25, 2011, the NRC staff issued a letter to SNC providing Inspection Report 05000321 and 366/2011009, regarding the Component Design Bases Inspection (CDBI) performed at HNP in July 2009. That letter concluded that the measures in effect at HNP to demonstrate compliance with the applicable provisions of 10 CFR 50.55a(h)(2) and 10 Tpamp 1"10-1 &IG_(!) n I LiiYX61

U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 2 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-1 7) are not acceptable.

3. A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance.
4. The NRC staff recognized that this changed position constituted a backfit.

However, the staff also maintained that it does not need to perform a cost-justified substantial safety backfit analysis, as is required by 10 CFR 50.109(a)(3). Instead, the staff stated that its change in position falls within the "compliance exception" to the staff's backfit analysis obligation which is provided by 10 CFR 50.109(a)(4)(i). In a letter dated June 17, 2011, SNC disagreed with the staff's conclusion in the May 25, 2011 letter that a backfit is necessary and that the compliance exception would properly apply to such a backfit and stated the rationale for appealing this decision.

5. The NRC responded to the SNC appeal by letter dated September 29, 2011, re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate. The stated NRC position was that while SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this license amendment was erroneous and has led SNC to be in violation of GDC-1 7 and 10 CFR 50.55a(h)(2). Because of having taken the position that former NRC approval of the license amendment was erroneous, NRC is exercising enforcement discretion for a duration to be determined after review of SNC's proposed corrective actions and schedule for compliance, to be submitted by SNC within 30 days of the NRC's September 29, 2011 letter.
6. There was no error or mistake made by the staff in approving the 1995 license amendment which established the existing HNP degraded voltage automatic protection scheme. The correspondence preceding the approval shows that the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed, understood, and acknowledged by the staff. No factual errors or omissions are at issue.

There were numerous letters and meetings between 1992 and 1995, with the issuance of the final SER in 1995 demonstrating that the NRC approved this change only after careful review.

7. The NRC letter of September 29, 2011 misreads IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations,"

to conclude that the standard does not permit manual action as part of the

U. S. Nuclear Regulatory Commission NL- 11-2032 Page 3 protection system, when in fact IEEE Std. 279-1971 contains no such prohibition.

8. The staff characterizes the existing HNP degraded voltage protection scheme as reliant solely on manual action. In fact, HNP has a fully automatic degraded voltage protection scheme. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition. In fact, the final 1995 SER credited routine manual control action as an integral element of the automatic degraded voltage protection scheme.
9. The NRC letter of September 29, 2011 cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate. Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.

Enclosure 1 of this letter provides additional discussion of the SNC appeal of the staff's backfit and compliance backfit determinations, with cited supporting documents provided in Enclosure 3. The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enclosure 2.

The NRC staff's May 25 and September 29, 2011, letters, if unaddressed by the EDO, will necessitate a license amendment related to HNP trip setpoints, anticipatory alarms and related requirements. To the extent that the current staff position may require a modification to the HNP license, Southern Nuclear preserves its rights to a formal hearing under Section 189(a)(1) of the.Atomic Energy Act, as amended, 42 U.S.C. § 2239(a)(1).

Southern Nuclear also requests the EDO to observe that development of the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior, 1991 enforcement action. As a matter of established Enforcement Policy, the staff should not reopen that closed action absent "special circumstances" (NRC Enforcement Policy, Sec. 2.3.8). Such special circumstances do not exist here, in that the staff had extensive and detailed information at the time it made its enforcement decision. Based on this Policy, the EDO should find that the enforcement resolution closes the matter from a backfit.

As previously stated in SNC's letter of June 17, 2011, SNC is working to develop a cost-effective resolution to the underlying technical issue, which concerns the margin - under worst-case circumstances and extremely degraded conditions -

U. S. Nuclear Regulatory Commission NL-1 1-2032 Page 4 between the minimum expected voltage on the safety-related,4160 V buses at HNP and the minimum voltage required to protect the safety-related equipment on these buses. To this end, SNC is evaluating options to increase this margin and by December 31, 2011 will provide a follow-up letter outlining the proposed technical solution with an implementation schedule.

This letter contains no formal NRC commitments.

Ifyou have any questions, please contact Mark Ajluni at (205) 992-7673.

Respectfully submitted, D. R. Madison Vice President - Hatch DRM/DWD/lac : Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception : Loss of Power Instrumentation Surveillance Requirements : Appeal to the EDO: Reference Documents cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, President and CEO Mr. D. G. Bost, Chief Nuclear Officer Mr. J. L. Pemberton, Senior VP & General Counsel Ms. P. M. Marino, Vice President - Engineering Mr. M. J. Ajluni, Nuclear Licensing Director RTYPE: CHA02.004 U. S. Nuclear Requlatory Commission Mr. J. T. Munday, Director - Division of Reactor Safety Mr. V. M. McCree, Regional Administrator Mr. W. C. Gleaves, NRR Project Manager Mr. E. D. Morris, Senior Resident Inspector - Hatch

Edwin I. Hatch Nuclear Plant Enclosure 1 Appeal to the EDO:

Backfit and Applicability of "Compliance Backfit" Exception

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception Introduction Southern Nuclear Operating Company (SNC) is the licensed operator of the Edwin I. Hatch Nuclear Plant (HNP). In a letter dated May 25, 2011, the Nuclear Regulatory Commission (NRC) staff advised SNC that the degraded voltage protection scheme at HNP did not comply with 10 CFR 50.55a(h)(2) and 10 CFR Part 50, Appendix A, General Design Criterion 17 (GDC-17). The May 25 letter acknowledged that the NRC staff's position - that "administrative controls to assure adequate voltage to safety-related equipment during certain design basis events" was not an acceptable method for compliance with 10 CFR 50.55a(h)(2) and GDC 17 - was a change in a NRC staff position and therefore constituted a backfit as defined in 10 CFR 50.109. The May 25 letter maintained, however, that no cost-justified substantial safety backfit analysis, as required by 10 CFR 50.109(a)(3), is required because the change falls within the "compliance backfit" exception to the staff's backfit analysis obligation in 10 CFR 50.109(a)(4)(i).

By letter dated June 17, 2011, SNC appealed to the NRC staff the staff's determination that the backfit qualified for the 50.109(a)(4)(i) "compliance backfit" exception. In a letter dated September 29, 2011, the NRC staff responded to the SNC appeal by re-affirming that the decision to use the "compliance exception" provision as allowed by 10 CFR 50.109(a)(4)(i) was appropriate. SNC hereby appeals this determination to the NRC Executive Director of Operations (EDO),

pursuant to the NRC Manual, Chapter 0514 (Management Directive 8.4).

SNC appeals the NRC staff's decision to issue a backfit under the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) related to the degraded voltage protection scheme at Edwin I. Hatch Nuclear Plant (HNP). SNC requests that the EDO reverse the NRC staff's determination that: (1) the HNP degraded voltage protection scheme does not comply with the applicable regulations and (2) the acknowledged backf it constitutes a "compliance backf it" under 10 CFR 50.109(a)(4). SNC requests the EDO find that HNP is currently in compliance with 10 CFR 50.55a(h)(2) and GDC 17 and that the NRC staff's change in position regarding the requirements of those regulations does not satisfy the "compliance backfit" exception to 10 CFR 50.109(a)(4)(i).

Background

In a February 23, 1995 NRC Safety Evaluation Report (SER), the NRC approved the reliance on administrative controls and manual actions at HNP for maintaining adequate voltage to protect Class 1E (safety-related) electrical equipment in the event of degraded voltage conditions. It was expressly acknowledged by the NRC that this protection scheme was a deviation from the guidance on degraded voltage protection provided in a NRC letter dated June 2, 1977, but after detailed review, the NRC determined the deviation was acceptable. In addition, this protection scheme was approved as a part of a license amendment for Improved Technical Specifications (ITS) with the approved SER issued March 3, 1995.

SNC has been in compliance with this approved degraded voltage protection scheme for over 16 years.

Enclosure 1 Page 1 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception The SER approving the deviation and license amendment also recognized that the HNP design configuration satisfied the requirements of GDC-17:

'With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10 CFR Part 50, Appendix A."

As a result of the Component Design Bases Inspection (CDBI) at HNP in July 2009, the NRC staff asserted that SNC was not in compliance with the degraded voltage protection requirements of 10 CFR 50.55a(h)(2) and General Design Criterion 17 (GDC-17). In its May 25, 2011 letter, the NRC staff stated that HNP was not in compliance with the degraded voltage protection requirements of GDC 17 and 10 CFR 50.55a(h)(2) and directed that HNP implement a backfit excluding reliance on manual action to maintain grid voltages. The NRC staff asserts that, although SNC has been in compliance with the 1995 license amendment approving the configuration of the HNP degraded voltage protection system, NRC approval of this 1995 license amendment was erroneous and, consequently, that SNC is in violation of GDC-17 and 10 CFR 50.55a(h)(2). Accordingly, the NRC staff asserts that the backfit qualifies for the "compliance backfit" exception codified at 10 CFR 50.109(a)(4)(i).

The NRC's regulations, for purposes relevant here, at 10 CFR 50.109(a)(1) define a backfit as:

"...the modification of ... design of a facility...or imposition of a regulatory staff position interpreting the Commission's regulations that is either new or different from a previously applicable staff position."

The NRC staff acknowledges that its current position is a change from the NRC position reflected in the 1995 SER approving the deviation from the 1977 guidance and "constitutes backfitting." More specifically, in the Evaluation attached to the September 29, 2011 letter denying SNC's initial appeal, the NRC staff recognizes at page 3 that "a deviation from the guidance on degraded voltage protection provided in the NRC letter dated June 2, 1977 was accepted by the NRC in a SER dated February 23, 1995."

While it is clear that the NRC staff's letter of May 25, 2011 seeks to impose a backfit, SNC believes that the NRC staff's reliance on the compliance backfit provision of 10 CFR 50.109(a)(4)(i) is misplaced. SNC's appeal of the NRC's decision to issue a backfit and to apply the "compliance exception" provision of 10 CFR 50.109(a)(4)(i) is based on the following:

(1) the 1995 approval of HNP's degraded voltage protection scheme was not based on a mistake of fact or error; (2) the approved configuration is adequate relative to risk and complies with applicable regulations; Enclosure 1 Page 2 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception (3) the "compliance backfif' exception is not applicable to a change in NRC staff position regarding compliance with a regulation; and (4) imposition of the backfit as a compliance backfit would be contrary to NRC's principles of good regulation in that it would not promote a stable regulatory environment.

I. The approval of the current HNP degraded voltage configuration in 1995 was not based on a mistake of fact or error.

A. The NRC staff in 1995 was cognizant of and understood the approved deviation from the 1977 guidance.

Contrary to the NRC staff's assertions underlying the current backfit, the 1995 approval of the configuration of the HNP degraded voltage protection scheme by the staff was not based on an error or mistake of fact. SNC submits that the historic correspondence between SNC and the NRC staff demonstrates that the NRC fully recognized in 1995 that its approval of the HNP system was a deviation from the 1977 NRC staff guidance.1 In effect, the NRC staff's analysis in 1995 was similar to the cost-justified substantial safety backfit analysis that SNC contends should be performed now as a condition to the imposition of the current backfit.

The NRC staff acknowledges that correspondence between SNC and the NRC and other documentation, including two (2) SERs, demonstrates that the NRC staff formally reviewed and approved the degraded grid voltage Loss of Offsite Power (LOP) and Loss of Coolant Accident (LOCA) scenarios for HNP. Those SERs examined the sufficiency of voltage for concurrent LOP and LOCA, the likelihood of such an event, and the positive safety consequences associated with additional degraded voltage alarms, operator monitoring and potential action, and the specific setpoints for degraded voltage relays that initiate automatic separation of the plant from the system. However, the NRC staff asserts that the 1995 approval was in "error" or a "mistake." The basis for that assertion appears twofold: 1) the NRC staff in 1995 "did not explain why" the deviation from NRC's 1977 guidance was approved and, therefore, was apparently without basis (e.g.

lack of information or based on inaccurate information), or 2) the 1995 conclusion to approve the license amendment including the deviation was an analytical error.

Contrary to the NRC staff's current rationale for asserting that NRC's 1995 SER was mistaken or otherwise in error, the contemporaneous documentation from the early 1990s demonstrates that the NRC staff at that time was fully aware and 1 The 1995 staff understood that the 1977 guidance was a position, not a regulation. The 1995 staff SER expressly referred to the June 2, 1977 letter as "current NRC staff guidance" and "Staff Positions" regarding onsite emergency power systems.

Enclosure 1 Page 3 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception cognizant of the issue at hand and of the resolution that it was approving. The documentation underlying the NRC's approval of the 1995 license amendment establishes that the deviation from the 1977 staff guidance was approved only after the particular facts and circumstances related to degraded grid on the Southern electric system and the HNP degraded voltage protection scheme were reviewed. The approval was risk-informed and appropriately considered the relative alternatives:

1. In 1982, EG&G, an NRC contractor, prepared a review of the degraded grid protection for Class 1E power systems at HNP (Enc. 3, Item 1). The contractor identified the design basis criteria, including GDC-17, IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations" and the NRC "Staff positions as detained in a letter sent to the licensee, dated June 3, 1977". The licensee provided the contractor with proposed changes to the Technical Specifications, allowable limits for setpoint and time delay, and LCOs applicable to the second level voltage monitors. Here, then, was manual action as a component of undervoltage protection, with relays set to operate and disconnect at 2912 V (70%).
2. In 1991, during an Electrical Distribution System Functional Inspection, the NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnection from offsite power supply. Thereafter, the staff issued an inspection report on August 22, 1991, and a Notice of Violation (NOV) on October 7, 1991. The violation was contested by the licensee by letter dated November 6, 1991.

The licensee maintained that the existing degraded grid protection scheme complied with the staff's positions in the June 2, 1977 letter.

Enclosure 3, Items 2, 3 & 4 are the Inspection Report, the NOV and the licensee's response, respectively.

3. A meeting was held between the licensee and the staff on November 16, 1992 to address the matter; seven full-time and two part-time NRC representatives attended (Enc. 3, Item 5 is handouts from the meeting).

Two licensee letters, dated November 22, 1993 and July 1, 1994 (Enc. 3, Items 6 & 7) were followed by another meeting with the staff on December 7, 1994 (January 10, 1995 meeting summary at Enc. 3, Item 8). The NRC responded with the SER on February 23, 1995 (Enc. 3, Item 9).

In summary, SNC and the NRC staff disagreed on a NOV, found common ground for a resolution that complied with GDC-17, the NRC staff evaluated that resolution and imposed additional conditions to which SNC agreed. Thus, there was no mistake or error in the NRC's approval of the license amendment that included a deviation from the June, 1977 guidance.

B. The NRC staff understood that the approved deviation included licensee commitments that added design features for enhanced safety. These Enclosure 1 Page 4 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception enhancements guard against spurious disconnections from the preferred backup power source, when available.

The NRC's 1995 SER for the degraded grid voltage protection scheme includes the following, which demonstrates the staff's imposition of requirements for design features to the system that enhance safety. For over 16 years, HNP has implemented those features, as part of the approved design. The SER states:

"The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:

1. The degraded voltage alarm relays should be included in the plant Technical Specification along with the degraded voltage relays that initiate automatic actions.
2. The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.

The licensee has agreed to these added conditions.

With the alternate approach, the staff concludes that both an offsite and onsite power system is available, each with the capability of providing power for the required safety components in accordance with GDC 17 of 10.CFR Part 50, Appendix A."

C. The 1995 SER expressly approved reliance on manual actions to respond to a narrow 3% band of degraded grid voltages. In addition, the SER acknowledged that certain class 1 E loads at voltage levels of 600 volts and below might not receive sufficient voltage upon automatic disconnection from the grid with the HNP configuration.

A description of the manual actions approved to respond to such degraded voltage conditions is contained in the staff's March 3, 1995 SER for the Improved Technical Specifications (ITS):

"...HNP credits manual actions in the range of 78.8% to 92% of 4.16kV.

Entry into this range is annunciated. The range specified for manual action indicates that sufficient power is available to the large ECCS pump motors. However, sufficient voltage for the equipment required for loss-of-coolant accident (LOCA) conditions may not be available at lower voltages. The required channels of LOP annunciation instrumentation ensure the initiation of manual actions to protect the ECCS and other assumed systems from degraded voltage without initiating an Enclosure 1 Page 5 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception unnecessary automatic disconnect from the preferred offsite power source. The LOP anticipatory annunciators are designed with a time delay of 65 seconds to reduce the possibility of nuisance annunciators while permitting prompt detection of potential low voltage conditions. HNP takes credit for the annunciators in restoring acceptable voltage levels.

Therefore, improved TS Table 3.3.8.1-1 is being added to the CTS

[Current Technical Specification] requirements. Additionally, ACTION B, addressing the annunciator function, is being added and the other functions are renumbered and amended to provide for the annunciation.

SRs [Surveillance Requirements] are also being added for the annunciator bus undervoltage and associated time delay relays."

In conclusion, the 1995 staff was informed, knowledgeable and engaged in the approval of the current HNP degraded voltage protection scheme. While the current staff may have a difference in professional opinion about that approval, that opinion is not a sufficient basis for a backfit and for an exception to the requirement for performing a cost-justified safety benefit evaluation.

I1.The current HNP degraded voltage configuration is adequate relative to risk and complies with the applicable regulations.

In the Sept. 29, 2011, NRC Evaluation of Licensee Backfit Appeal, on page 4 the NRC staff maintains that the error in the NRC's 1995 SER was that the 1995 SER:

"...was not based on the guiding principle of the NRC position that the sole reliance on manual controls for degraded grid voltage protection may result in the Class 1E bus voltages being too low for operation of safety-related equipment but high enough to prevent separation of the safety buses for the offsite power supply." (italics supplied)

Similar wording is found elsewhere in the Evaluation. For example, on page 6 the NRC staff states the IEEE Std. 603-1991 requires design basis documentation for justification of "permitting initiation or control subsequent to initiation solely by manual means" and on page 7 the NRC concludes that "...the backfit per the compliance exception..." issued to SNC "...for its reliance solely on manual controls for degraded grid voltage protection was appropriate".

Contrary to this characterization, HNP does not rely solely on manual controls for degraded grid voltage protection. The manual actions "credited" to prevent inadequate voltage conditions were limited to manual actions by plant operators in a specific band of degraded voltages followed by automatic actuation at a lower system voltage setpoint:

"The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3%

band between 91% (3786 volts) and 88.34% (3675 volts) certain class 1E Enclosure 1 Page 6 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception loads at voltage levels of 600 volts and below may not receive sufficient voltage." - SNC to NRC letter dated November 22, 1993 (Enc. 3, Item 6)

"...the degraded grid protection system uses manual action instead of automatic disconnect in the range of the deadband. Accordingly, GPC

[the licensee] has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent,

[plant] operators will initiate a 'one hour to restore' action statement. If voltages are not restored within one hour, a plant shutdown is then initiated." - GPC to NRC letter dated July 1, 1994.(Enc. 3, Item 7)

As can be observed in the handouts from the NRC and licensee meeting of November 16, 1992 (Enc. 3, Item 5), and the attachment to the licensee's November 22, 1993 letter (Enc. 3, Item 6) the staff was aware that 2 automatic disconnection from the grid would occur at 88.34% of 4160 volts.

Neither GDC-17 or 10 CFR 50.55a(h)(2) expressly prohibit manual actions in response to degraded voltage conditions. GDC-1 7 is descriptive of offsite and onsite power supplies and speaks to the importance of minimizing the probability of coincident loss of power supplies - implicitly in order of safety importance -

power from the unit, from the grid and from onsite backup power supplies.

"Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies."

The HNP license includes requirements for anticipatory alarms, their setpoints and periodic testing (surveillance), and a limiting condition for operation (LCO).

These requirements address the potential for a grid voltage drop to the minimum expected level due to a plant trip, which is the most likely grid event. The express license requirements do not require a backfit. Manual action by plant operators and the operators of the Southern electrical transmission grid system is a routine controlled activity, guided by a real-time N-1 contingency analysis, to maintain the grid voltage within the normal expected range, thus minimizing challenges to the automatic degraded voltage protection scheme by a degraded grid condition. This approach has been very successful; a review of system operating records and plant logs dating back to the March 14, 1993 degraded grid event described in the 1995 SER found no instance of the degraded grid alarm having ever annunciated at HNP.

GDC-17 states that "an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The 2 Current tap setting is 78.8% of 4160 volts.

Enclosure 1 Page 7 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception safety function.. .shall be to provide sufficient capacity and capability.. .as a result of anticipated operational occurrences." HNP's design and operation meets this requirement in that it has the capacity and capability for the anticipated grid conditions, including N-1 contingencies. In addition, the potential for a degraded grid at HNP (although unanticipated) is minimized by the plant and grid operational features described herein, and results in an extremely low probability of occurrence.

A risk-informed evaluation estimates that the expected frequency of the pertinent technical issue, automatic actuation of safety-related equipment due to a loss of coolant accident concurrent with a degraded grid condition below the degraded grid alarm setpoint, is on the order of 1.0 E-9 per year and is considered to be of low safety significance. SNC has determined this value through a best estimate approach with appropriate conservatism.

The September 29, 2011 NRC Evaluation of Licensee Backf it Appeal cited the 1976 Millstone and 1978 Arkansas Nuclear One (ANO) incidents to support the contention that the HNP degraded voltage protection scheme is inadequate. It should be noted (as the NRC concluded in its own documented evaluations) that neither of these two events was due to grid voltage conditions below expected values. The plant voltage issues were due instead to inadequate plant design for the anticipated grid and plant operational conditions. Evaluation of these events shows that for HNP the existing relay settings do not operate during motor starting and operating practices to keep operators informed of expected grid conditions would preclude the Millstone scenario, while the ANO incident is not relevant due to differences in switchyard design.

10 CFR 50.55a(h)(2), specifies the codes and standards applicable to nuclear power plant protection systems, and incorporates by reference IEEE Standards.

For HNP, IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," is the requirement applicable to the degraded grid protection system. To support its current "compliance backfit" argument, the NRC staff relies on its interpretation of the "intent" of IEEE Std. 279-1971, rather than applying language actually found in the standard. Notwithstanding its acknowledgement on page 6 of the Evaluation that IEEE Std. 279-1971 "acknowledges the use of manual action and initiation of protection systems by manual actions," the staff adds its own gloss to the language of the standard in order to narrow its scope by stating that "manual action as discussed in Section 4.17 is intended to be 'in addition to,' as a backup, and not 'in lieu of' the automatic initiation requirement of Section 4.1."

Again, for the HNP degraded grid protective scheme, manual action by operators is taken before the plant conditions for automatic actuation are reached.

Specifically, the November 22, 1993 GPC letter (Enc. 3, Item 6), the July 1, 1994 GPC letter to the NRC (Enc. 3, Item 7), the January 10, 1995 NRC meeting notes (Enc. 3, Item 8), and February 23, 1995 NRC SER (Enc. 3, Item 9) address in detail the plant's response to degraded grid conditions, the setpoints for automatic disconnection, and anticipatory alarms and potential manual actions at Enclosure 1 Page 8 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception below 92%. An automatic degraded grid trip for voltages below 88.34% (currently 78.8%) of bus voltage was approved by the NRC staff for the automatic disconnect, provided that the anticipatory alarm relays and degraded voltage relays came into the Technical Specifications. (The Technical Specification surveillance requirements for the relay setpoints and time delays are provided for reference in Enc. 2.)

Manual action instead of automatic trip is applicable, then, only to a narrow band of voltages above the automatic trip level. Once the trip setpoint is reached, the actuation of the protection system goes to completion without manual intervention, in accordance with IEEE Std. 279-1971 at §4.16 on pg. 10. No regulation, order or commitment precludes anticipatory manual action for degraded grid voltages as a component of a plant's degraded grid configuration.

Ill. The "compliance backfit exception" is not applicable to the change in NRC staff positions in this matter.

"The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact." See 50 Fed. Reg.

38097, 38103 (Sept. 20, 1985).

Whether the NRC staff's invocation of the compliance backfit exception in 10 CFR 50.109(a)(4)(i) supports the backfit discussed in its May 25, 2011 letter depends on whether that exception may be used to avoid a cost-justified substantial safety backfit analysis when the NRC staff changes its position regarding what is necessary to comply with a regulatory requirement, as opposed to whether a facility or license is in compliance with a clearly stated regulatory requirement. As stated in 10 CFR 50.109(a)(4)(i), the exception applies where "a modification is necessary to bring a facility into compliance with a license or the rules or orders of the Commission, or into conformance with written commitments by the licensee." The backfit imposed by the NRC staff's May 25, 2011 letter incorrectly relies on the "compliance backfit exception" to avoid the obligation of the NRC staff to perform a cost-justified substantial safety backfit analysis.

The NRC staff's rationale for invoking the compliance backfit exception is that it disagrees with the NRC's 1995 determination that the HNP degraded grid protection system satisfies both 10 CFR 50.55a(h)(2) and GDC-17. As stated on page 3 of the Sept. 29, 2011 NRC Evaluation of Licensee Backf it Appeal:

"...the backfitting action is necessary for compliance with GDC-17 and 10 CFR 50.55a(h)(2) and is consistent with applicable guidance and practices in effect at the time the NRC staff erroneously approved the use of manual actions for controlling voltages at HNP."

This statement is instructive. First, the NRC staff says that the backfitting action is necessary for compliance with two specific regulations. As set forth above, however, the NRC in 1995 expressly addressed the compliance of the HNP Enclosure 1 Page 9 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception system under the same regulations and came to a different conclusion than the NRC staff does today. Because the NRC staff's position in 2011 is not based on the express language of either regulation but on the "intent" of the regulations, the difference of opinion is clearly a change in NRC staff position, not a mistake or error by the NRC in 1995.

The NRC staff's invocation of the compliance backfit exception under these circumstances would improperly enlarge the scope of the exception from "omissions or mistakes of fact" to encompass alleged "approval errors" for deviations to staff positions which were based on accurate and complete facts.

Application of the compliance backfit exception in this way would be inconsistent with the clear language and intent of the backfit rule. 'The compliance exception is intended to address situations in which the licensee has failed to meet known and established standards of the Commission because of omission or mistake of fact. It should be noted that new or modified interpretations of what constitutes compliance would not fall within the exception and would require a backfit analysis and application of the standard." See 50 Fed. Reg. 38097, 38103 (Sept.

20, 1985). See also NUREG 1409 § 3.1 at pg. 12 (which cites this statement from the Federal Register notice).

Second, the NRC staff says that backfitting action is "consistent with" historic guidance. NRC guidance documents are not regulations. They have not gone through the Administrative Procedures Act process and the vetting appropriate for rules. For example, Branch Technical Position (BTP) 8-6 (Rev. 3, March, 2007),

"Adequacy of Station Electric Distribution Voltages," is found in NUREG 0800, Chapter 8 as part of the Standard Review Plan. The first footnote in BTP 8-6 includes: "...the Standard Review Plan is not a substitute for the NRC's regulations, and compliance with it is not required." Thus, the BTP is not a regulation. "Consistent with" is not equal to "mandated by."

Important distinctions apply to "legal requirements", "commitments" and "staff positions" in the context of backfits:

  • Legal requirements are contained in explicit regulations, orders, and plant licenses (amendments, conditions, technical specifications).
  • Written commitments are contained in docketed correspondence, including responses to Generic Letters.
  • "Staff positions" are explicit interpretations, and are contained in documents such as Generic Letters, and to which a licensee has previously committed.

"Positions contained in these documents are not considered applicable staff positions to the extent that the staff has, in a previous licensing or inspection action, tacitly or explicitly excepted the licensee from part or all of the position."

Enclosure 1 Page 10 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception "Imposition of a staff position to which a licensee has previously been excepted is a backfit."

(NUREG-1409, Appendix D, page 13 "NRC Manual Chapter 0514, NRC Program for Plant-Specific Backfitting of Nuclear Power Plants")

(Emphasis added)

Also, NUREG-1409, Section 3.3, "Plant-Specific Backfits," states at question 7 (emphasis added):

"If the staff previously exempted a licensee from a legal requirement or approved position, it is not applicable to that licensee for purposes of backfit consideration."

The 1977 letter is not a regulation, order or condition in the HNP licenses. The 1977 letter's provisions with respect to degraded grid and compensatory manual actions at HNP may not be considered an applicable staff position for purposes of imposing a backfit because the licensee was previously excepted.

Nonetheless, today the staff maintains, on page 7 of the September 29, 2011 NRC Evaluation of Licensee Backfit Appeal (emphasis added), that:

"...although GDC-17 and 10 CFR 50.55a(h)(2) do not expressly prohibit manual actions in all situations and make reference to the use of manual actions for certain situations, the NRC's position has been that the protection feature be automatic, which is not being met at HNP."

Accordingly, the NRC staff invocation of the compliance backfit exception to include modifications which are necessary to make a facility consistent with staff positions to which a licensee has previously been excepted is inconsistent with NRC guidance relative to application of the backfit rule.

Instructive for the EDO on this appeal is a particular question and response found in NRC staff guidance (NUREG-1409, Section 3.1, question 7). The answer addresses three cases, one involving an explicit exemption 3 from a legal requirement or approved staff position and the other two involving the staff's "tacit" approval associated with previous staff review of a licensee action or program or due to the passage of time. In both "tacit"cases, if the staff were to require additional action by the licensee, the staff's action would be a backfit, but might not be a compliance backfit (or meet other exceptions listed in the backfit 3 Today the staff reads the guidance narrowly, as applicable to staff exemptions in accordance with 10 CFR 50.12. However, an exemption under that provision is limited to an "exemption from the requirements of the regulationsof this part" and not applicable to exemptions from staff positions.

Enclosure 1 Page 11 of 12

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Backfit and Applicability of "Compliance Backfit" Exception rule). "Explicit exemption would be done formally in writing."4 An approved staff position, then, for which the licensee has been explicitly exempted, "is not applicable to the licensee for the purpose of backfit consideration." In other words, such a staff position cannot be relied upon by the current staff for a compliance backfit exception, as urged by the current staff.

Accordingly, the compliance exception was created to address situations when known and established standards were overlooked or requirements were not imposed due to mistakes of fact or inaccurate or incomplete information. Such is not the case in this appeal. The backfit rule requires that the staff be bound by its "previous licensing actions.. .that explicitly excepted the licensee from part or all of the position." The history of the approval of the 1995 deviation and license amendment also demonstrate that the current HNP degraded voltage protection scheme was intertwined with the resolution of a prior enforcement action and, as a matter of policy, the staff should not reopen that closed action. In accordance with the NRC's Enforcement Policy, Section 2.3.8, "special circumstances" must be present for the staff to "reopen" closed enforcement actions. Special circumstances do not exist here, when the staff had extensive and detailed information at the time it made its enforcement decision.

Conclusion In conclusion, SNC appeals to the EDO regarding the staff's determination that a backfit is warranted and to the staff's application of the 10 CFR 50.109(a)(4)(i),

"compliance exception," to avoid the obligation to perform a cost-justified substantial safety benefit analysis prior to imposition of a backfit. The NRC licensed HNP for its current degraded voltage protection scheme including mandating provisions and conditions in its Technical Specifications. In addition, SNC submits there is documentation which supports that the 1995 staff did not "erroneously approve the use of manual action" to respond to degraded grid conditions. At issue here is a difference in professional opinions between the 1995 staff and the current staff. Finally, there are no new technical requirements, rules or regulations which would justify a change in the NRC staff's position.

Therefore, SNC has concluded that the HNP degraded voltage protection scheme continues to meet the requirements of GDC-17 and 10 CFR 50.55a(h)(2) and no compliance backfit is warranted.

4 Note the guidance does not reference "specific exemptions" (the phrase used in 10 CFR 50.12), or 50.12 (or its predecessor) or any particular precondition but "formal." "Explicit approval" could be provided in an inspection report, but "usually made in a safety evaluation reports rather than inspection reports." NUREG-1 409, Section 3.3, question 1.

The licensee's July 1, 1994 letter stated, "...GPC requests formal NRR staff review and approval of this deviation." (TAC No. 80948).

Enclosure 1 Page 12 of 12

Edwin I. Hatch Nuclear Plant Enclosure 2 Loss of Power Instrumentation Surveillance Requirements

Edwin I. Hatch Nuclear Plant Loss of Power Instrumentation Surveillance Requirements LOP Instrumentation Surveillance Requirements Source: Hatch Units 1 & 2 Technical Specifications Table 3.3.8.1-1 REQUIRED ALLOWABLE CHANNELS SURVEILLANCE VALUE FUNCTION PER REQUIREMENTS FUNCTION (% 4.16 kV)

.4.16 kV Emegency Bus Undervoltage (Loss of Voltage) a.Bus Undervoltage 2 SR 3.3.8.1.2 > 2800 V (67.3%)

SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.2 s 6.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4

2. 4.16 kV Emegency Bus Undervoltage (Degraded Voltage) a.Bus Undervoltage 2 SR 3.3.8.1.2 > 3280 V (78.8%)

SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.2 s 21.5 seconds SR 3.3.8.1.3 SR 3.3.8.1.4

3. 4.16 kV Emegency Bus Undervoltage (Annunciation) a.Bus Undervoltage 2 SR 3.3.8.1.1 >3825 V (92%)

SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 b.Time Delay 2 SR 3.3.8.1.1 5 65 seconds SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4 Enclosure 2 Page 1 of 1

Edwin I. Hatch Nuclear Plant Enclosure 3 Appeal to the EDO:

Reference Documents

Edwin I. Hatch Nuclear Plant Appeal to the EDO: Reference Documents

1. February, 1982 EGG Report to NRC

Subject:

Degraded Grid Protection for Class 1 E Power Systems

2. August 22, 1991 - NRC Inspection Report 50-321/91-202 & 50-366/91-202
3. October 7, 1991 - Notice of Violation; NRC Inspection Report 50-321/91-202 & 50-366/91-202
4. November 6, 1991 -GPC Letter to NRC

Subject:

Response to Notice of Violation

5. November 16,1992 - GPC meeting with NRC

Subject:

HNP Degraded Grid Issues

6. November 22, 1993 - GPC letter to NRC

Subject:

Degraded Grid Protection

7. July 1, 1994 - GPC letter to NRC

Subject:

Degraded Grid Protection

8. January 10, 1995 - NRC letter to GPC

Subject:

Summary of December 7, 1994 meeting

9. February 23, 1995 - NRC letter to G PC

Subject:

SER for Degraded Grid Voltage Relay Setpoints Enclosure 3 Page 1 of 1

A)eeid eac .. I4- 45tauo F. -.iG-EA-5754 FEBRUARY 1982 DEGRADED GRID PROTF!TION FOR CLASS 1E POWER SYSTEMS, Ralf EDWIN I. HATCH S;-%.4,EAR POWER PLANT, UNIT NOS. 1 AND 2 /'eaK A)!;t e A;f r/ S C11-,

A. C. Udy U.S. Department of Energy IdahIo Opratlon$ Office

  • Idaho National Engineering Laboratory 11111110 011%awalift man" BM W an
  • O= . -414nwww i I ,-. -i =

TIns Is an informal rtpofl Intended for use as a preliminary or working document f.*pared for thr

u. S. Nuclear F&;. atc Domi SS on Under DOE.Lont:- Ac716Di FIN No. A6429 n E~

U;'-107 8204-26 Pz' ':LS q;Z04140575 PDR

- E .. _

F'.  :..*-*'-*ne,'* I.. .. ' -.. '-4 .4* *205 .M" 070* d~m o. ~i*.

fgn H S IT 64 6tf INTERIM REPORT ACCeSsion No .

Report No _

Contract Program o* Project Tile:

Selected Operating Reactor Issues Progra.m (Ill)

Subje"t of tNa Document; Degraded Grid Protection for Class lE Power SystemS, Edwin I. Hatch Nuclear Power Plant, Unit Nos. 1 and 2 Type ol Document Informal Report Author(s),

A. C. Udy Oate of Oocument.

February 1982 Responsible NRC/DOE Individual and NRCIDO£ Office r Divitskm:

R. L. Prevatte, Division of Systems Integration, NRC This dCoeument was prepared primarily for prelimitary or internal use. It has not received full review and approval. Since there may be substantive changes. this document should not be considered Vreial.

EG&G Idaho Inc Idaho Falls. Idaho $3415 Prepared for the 4 U.S. Nuclear Regulatory CommissiOn Washington, D.C.

Undier DOE Contract No. DE0CQ7.?6I10167o NRC FIN No - 9-.--

INTERIM REPORT 1011 61 W^-011 'A' M,

0451 J V

DEGRADED GRID PROTECTION FOR CLASS 1E POWER SYSTEMS EDWIN I. HATCH NUCLEAR POWER PLANT, UNIT NOS. 1 AND 2 February 198?

A. C. Udy Reliabtlity and Statistics Branch Engineering Analysis Division EG&G Idaho, Inc.

0 TAC Nos. 10026 and 11262 Docket Nos. 50-321 and 50-366

IN , -

b ABSTRACT This EG&G Idaho, Inc. report reviews the susceptibility of the safety.

related electrical equipment at the Edwin I. Hatch Nuclear Power Plant to a Sustained degradation of the offsite power sources.

FOREWORD This report is supplied as part of the "Selected Operating Reactor Issues Programs (III)" being conducted for the U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Division of Licensing, by EG&G Idaho, Inc., Reliability and Statistics Branch.

The U.S. Nuclear Aegulatory Commission funded the work under authorization BMR ?0 19 0) 06, Fin No. A6429.

Ii

.-. m

SEINT BY: :.op-"1 C~e lel- , l6-Z'  : IL: _ ' ,. .... ,:,:.  ;:.

CONTENTS

.O INTRODUCTION ......................................... ......... I 2.0 DESIGN BASE CR1 7?RIA ... ............ ........... ................. 1 3.0 EVALUATION ...................................................... I 3.1 E*xsting Undervoltage Protection .......................... 2 3.2 'odtflcations .............................. ,s., 2 3.3 01scuss ion ................. . ...... .....

. 3

4.0 CONCLUSION

S ..................................................... 5 5 .0 REFERENCES ..................... ............... 5

  • Fe e a as e ee e. . e I j i ~~ t e it B e e .o l o 0 Si'

5ENT B'(:CoPj Oeneral SENT ~ Ieneral06-26-91 B~: i i: 46)4 2029445474-i 0 8?0 205 7 6103 6ý8~~ 414 DEGRADED GRID Ft nTECIION FOR CLASS IE POWER SYSTEMS EDWIN I. HATCH NUCLEAR -9WER FLANT, UNIT MOS. 1 AND 2 1.0 TNTRODUCTION On June 2, 1977, the NRC requested the Georgia Power Company (GPC) to assess the susceptib~lity of the safety-related electrical equipment at the Edwin I. Hatch Nuclear Plant Unit 1 to a sustained voltage degradation of the offs te source and interaction of the offslte and ons!,e emergency power Systems. The letter contained three positions with which the current design of the plant was to be compared. After comparing the current destgn to the staff positions. GPC was required to either propose modifications to satisf the positions and criteria or furnish an analysis to substantiate that t4e existing facility design has equivalent capabilities.

GPC replied to the NRC letter on July 22. 1977,2 GPC supplied addi-tional information a~d technical specification changes on Ortober g, 19803 and on May 21, 1981. On October 2, 1981, GPC submittal modified techni-cal spe:-, ication changes fcr Unit No. I and similar technical specifica-tion changes for Unti No. 2.- This submittal had a typing error corrected on December 2, 1981,° Adoitional information Isfound in GPC letter5 dated September 17, 1976,' and January 12, 1982.° On January 26, 1981.

GPC suimitted all of the revised pages for the Unit 1 technical specif*

tions..

2.0 DESIGN BASE CRITERIA The design base criteria that were applied In determining the accepta-bility of the system modifications to protect the safety-related equipment from a sustained degradation of the offsite grid are:

1. General Design Criterion 17 (GDC 17), "Electrical Power Systems," of Appendix A, "General D1t8 gn Criteria for Nuclear Prwer Plants," of 10 CFR 50
2. IEEE Standar' 279-1971, "Criteria fL' ¶otection Systems for Nuclear Power Generating Stations"
3. IEEE Standard 308-1974, "Class 1E 2wer Systems for Nuclear Power Generating Stations"
4. Staff positions as detailed In a letter sent to the licensee, dated June 3, 1977 ANSI Standard C84.1-1977, "Voltage Ratingi for Electri-cal Power Systems and Equipment (60 HZ).* 3 3.c 4LUATION.

This section provides, In Subsection 3.1, a brief description of existing und- age protection at the Hatch Station; in Subsection 3.,2 a descriptior 'licensee's proposed scheme for the ..econd-level und..

voltage prc on; and in Subsection 3.3, a discussion of how the system meets the ,, ribase criteria.

I

F I111 ______,_ý!'- 4 4

3.1 Existing Undervoltage Protection. The previous de'ign utilized four undervoltage relays on each 41OVI Mass 1E emergency hus. They were arranged in a one-out-of-two-taken-twice logic scheme. Tie relays were set to operate at a voltage of 2912V (70%). These relays were used to sense a loss of offslte power. Should the voltage on the Class 1E buses fall the setpofnt, autoeatic fast transfer is initiated to the alternate -

source by this relay logic and the diesel generators are started. If the alternate source is not available, the buses are load-stripped and the preferred and alternate source breakers are tripped and locked-out. As the diesel generators reach 90% of rated voltage and frequency, the diesel.

generator bus breaker iS automatically closed. The undervoltage condition is also annunciated in the main control room.

This system disables the load-shed featurc once the Class lE buses are being supplied by the diesel generators. Prior to the modification pro-rosed in 1976, this was not disabled. 5 Non-essential loads, howeve, are load-shed when an accident signal exists whether the Class IE buses are being supplied from the offsite or the onsite power sources.

3.2 Modifications. To protect the Class 1E safety-relate' equipment from the errects or a degraded grid condition GPC has proposed ,:hanging the setpoints on the existing undervoltage relays. The relays used are Westinghouse type CV-7 inverse-time undervoltaqe relays. The two degraded voltage relays, arranged In a two-out-of-two 1kglc, will have a nominal

'Pint of 3?80V (78.81 of bus voltage) with a time delay of less than or 4ual to 21.5 seconds. When a loss-of-voltage occurs, two other relays.

also utilizing a two-out-of-two logic, will operate at a setpoint Of greater than or equal to 2800V (67.3% of bus voltage) with a time delay of less than or equal to 6.5 seconds. GPC has submitted a diagram showing the relay charateristics both above and below these nominal values. 8 Upon a trip signal from both degraded voltage relays or both loss-of-voltage relays the sequence of events will be as stated In Subsection 3.1, except that the operation of any one of the four mentioned relays will initiate the start of the diesel generator associated with that bus. The voltages and time delays specified are one point on the calibration curve for that relay. The relays operate with less time delay at lower voltages, and a greater time ,!tlay at hiqher voltages. GPC has shown that the operating characteristics of the relays will not spuriously trip the Class IE busct from offsite power for all expected combinations of offilte grid voltage and unit loadS.

Load-shedding is blocked once the diesel generator is supplying p7,er to its Class lE bus, except for non-essential loads, by use of a "b" co.-

tact of the diesel-;enerator breaker. The lad shedding is reinstated should the diesel generator breaker subsequently reopen. AS stated above, this Is already incorporated in the existing logic circuit.

Proposed changes to the plant's technical specifications, adding the surveillance requirements, allowable limits for the setpoint and time delay, and limiting conditions for operation for the second-level undervoltage monitors, were also furnished by the licensee. Bases for limiting condi-tions of operation as well as bases for surveillance requirements per-taining to these relays were also included in the technical specification changes. I 2

SENT BY:CoPY Oeneral SEN B:Coy eneal06-26-91 11:E50A 2029445474-ý 205 870 6100 I#15 3.3 Discussion. The first position of the NRC staff letter 1 required that a secoR level of undervoltage protection for the onsite Power system be prokided. The letter stipulates other criteria that the undervoltage protection must meet. Each criterion Is restated below followed by a dis-cussion regarding the licensee's compliance with that criterion.

I. 'The selection of voltage and time setpolnts shall be determined from an analysis of the voltage requireents of the safety-related loads at all onsite distribution system levelS."

GPC has analyzed for the voltage requirments for the sofety-Stlated loads at all onsite distribution system levels. These studies have contributed to the selection of the proposed relay settings.

2. "The voltage protection shall include coincidence logic to pre-clude spurious trips of the offsite power sources."

The relay logic is arranged In'a tw-out-of-two logic that satisfies this criterion.

3. "The time delay selected shall be based on the following conditions:
4. The allowable time delay, including margin, shll not exceed' the maximum time delay that is assumed in the FSAR accident analysis.I The bases for limiting conditions of operation submitted by the licensee states that the proposed time delay.

including margin, does not exceed the maximum time delay as analyzed in the FSMR.

The proposed time delay will not be the cause of any thermal damage to the safety-related equipment. The equipment is rated to operate at the setpoitnt voltage for in excess of 30 seconds.

b. "The time delay shall minimize the effect of short-duration disturbances fram reducins the unavailability of the offsIte power source(s)."

The licensee's proposed time delay characteristics provide a time delay long enough to override any short inconsequen-tial grid disturbances. Any voltage dips caused from the starting of large motors will not trip the offslte sou'-P C. "The allowable time duration of a degraded voltage condition at all distribution system levels shill not result in fail-ure of safety systems or components."

A review Of the licensee's voltage analysis 3 indicates that the time delay will not cause any failures of the 3

SENT BY:CoPV General SENT Y~CoY Genr'al06-26-91i 1:Se5Ol 20294454'i4-)0 7 60 205 870 6108 1

  1. 16' safety-related equipment since the relay, characteristics will disconnect a degraded source of AC power before the Stall rating o. in.t Pu- pvent 1 exCeeded.
4. "The voltage monwt-t 3tomiacally Inttiate the disconnec-tion of offsite whenever the voltage setpoint and time-delay limit. ,: "xceeded."

A review of the icensee's proposal substantiates that this cri.

terion Is met.

5. 'The voltage monitors shall be designed to satisfy the require.

meits of IEEE Standard 279-1971.

The licensee has stated in his submittal that all circuits associated witN Jhe undervoltap relays meet IEEE Stan-Olard 279-1971. .°

6. "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip SetpointS with minima and maximum limits, and allowable values for the Second-level voltage protection monitors,"

The llc¢n*ee's latest draft proposal for technical specification changes ', includes all of the required items except for Instru-ment check. The instrument check is normally done by.vertf ng that normal voltage is present at the input to each undervoltage relay. The Hatch station does not have voltmeters or indicators at this location, therefore the Instrument check is not applicable. Analyses have been performed which assurte that the range between the maximum and the minimum settings (allowable limits) will not be the cause of spurious trips of offsite power nor will they allow the voltage to be so low as to allow damage to the safety equipment.

The second NRC staff position requires that the system design auto-matically prevent load-shedding of the emergency buses once the onsfte sources are supplying power to all sequenced loads. The load-shedding must also be reinstated if the onsite breakers are tripped.

GPN tates that this feature is already incorporated in the circuit design,'P,° A review of the logic circuitry substantiates that the load-shed is blockedby a contact of the dlesel-gentrator breaker. All non-eSsential loads are, however, load-shed when the onsitt source is supplying puwer to the thass 1E buses.

The third NRC staff position requires that certain test requirements be added to the technical specifications. These tests were to demonstrate the full-functional operability and independence of the onsite power sources and are to be performed at least once per 18 months during shutdown. The tests are to simulate loss of offsite power in conjunction with a simulated safety Injection actuation signal and to simulate interruption and subse-quent reconnection of onuite power sources. These tests verify the proper 4

a - I operation of the load-shed s...tem, the load-shed bypiiss when the emergency diesel generators are supply..q power to their respective buses, and that Lhere IS no adverse Interaction between the onsite and offsIte power sources.

The testing procedures proposed by the licensee do comply with this position. Load-shedding when offsite power Is tripped Is tested. Load-seqL*ncing, once the diesel generator is supplying the safety buses, is testet,. A simulated loss of the diesel generator and subsequent load-shedding and load-sequencing once the diesel generator iS back on-line ,s tested. The time durations of the tests will verify that the time deley of the undervoltage relays Is sufficient to avoid spurious trips and that the load-shed bypass circuit Is functioning properly.

4.0 CONCLUSION

S Based on the information provided by GPC. it has been determioied that -

the proposed changes do comply with NRC staff position 1. All of the staff's requirements and design base criteria have been met. The setpoint and time delay will protect the Class 1E equipment from i sustained degraded voltage condition of the offsite power source.

The existing load-shed circuitry does comply with Staff position 2 and will prevent adverse interaction of theoffsite and onsite emergency power systems.

The proposed changes to the technical specifications do adequately test the system modifications and do comply with staff positto'n 3. The surveillance requirements, limiting conditions for operation, minimum and maximum limits for the trip point, and allowable values satis'y staff position 1.

It is therefore concluded that the mogifications and jhr proposed technical specification changes for Unit I and for Unit 2 ,Ire acceptable. These new setpoints and time delays have been i.nplemiented and It is, therefore, recommended that the changes to the techn.cal* specifica-tions be ipproved atid Implemented at the earliest opportunit.y.

S.0 REFERENCES

1. NRC letter, V. Stello tj C. F. Whitmer, GPC, dated June 2, 1977.
2. GPC letter, C. F. Whitmer, to Office of Nuclear Reactor Regulation, NRC, *Emergency Power Systems, July 22, 1977.
3. GPC letter. W. A. Widner to Office of Nuclear React'or Regula.lon. NRC,

.Response to Request for Additional Information--System Voltage Study,"

October 9, 1980.

J. GPC letter. J. T. Beckham to Office of Nuclear Rector Regulation, NRC, "Emergency Power Systems,' May 21, 1981.

5

W "..-

1FNOW I-- dý

. * .*4

5. GPC letter, W. A. Widner to Uirt.-tor of Nuclear Reactor Regulation.
  • , CEmergency Power Systems,' October 2, 1981.

f6. Gýt letter, .j T. Beckham to Oirector of Nuclear Reactor ReguTation, kC[, 'Revised Technical Speciflcations for Degraded System Vo1tage,*

.'..*ir 2. 1981.

  • CK fitter, C. F. Whitmer to Office of Nuclear Reactor Regu'atton.

H&*C, ^Operation During Degraded Grid Voltage Conditions, September 17, 1976.

8. GPC letter, J. T. Beckham to Division of Licensing, MRC, "Adequacy'-of Stationv Electric Distribution System Voltages, Response to RequeSt for Aoditonai Information,' January 12, 1982.
9. U'" letter, W. A. Widmer to Director of Nuclear Reactor Regulation,

".mergency Power Systems," January 26, 1962.

10. General Design Criterion 17. "Electric Power Systems." of. AppendIx A, "General Deslign Criterft for Nuclear Pover Plants," to 10 CFR Part 50, Domestic Licensing of Production and UtiliZation Facilities.%
11. IEEE Standard 279-1971, *Criteria for Protection Systems for Nuclear Power Generating Stations."
12. IEEE Stafndaru 308-1974, "Standard Criteria for Class IE Power Systems for Nuclear Power Generating Stations.'
13. ANSI C84.1-1977. "Voltage Ratings for Electric Power Systems and Equipment (60 HZ)."

4 6

,UNITED

ý%A STATES NUCLEAR REGULATORY COMMISSION

£-* V wASHIMOT04, 0. C. MQSS,

.. Aiy T 22, 1991

.ocket No. SC-321 50-366 Mdr. W. G. Hairston, III Senior Vice President Georgia Power Company 4C Inverness Center Parkway P.O. Box 1295 Birmingham, Alabama 35201

Dear Mr. Hairston:

-SUBJECT; ELECTRICAL DISTRIBUTION SYSTEM FUNCTIONAL INSPECTION-AT-HATCHt (50-32'1/91-202; 50-366/91'202)

We are forwarding the repurt of a special electrical distribution system functional inspection (EDSFI) performed June 10 through July 12, 1991, involv-ing activities authorized by Operating License Nos. DPR-57 and NPF-5 for the Hatch Nuclear Plant, Units 1 and 2. This inspeCtion was conducted by tht Special Inspection Branch of the Office of Nuclear Reactor Regulation with the

support of Region II. An exit meeting was held on July 12, 1991, during which-we discussed the team'.s findings with members of your staff.

The areas examined during the inspection are discussed in the ew-closed copy of

ýour inspection report; The inspection team assessed the desigr,, design imple-mentation and technical support of the electrical distributiun Systen (EDS).

The inspection consisted of a selective review of EDS design calculations, relevant procedures, representative records, installed equipment and interview-with engineering and technical support staff.

-hE design and design implementation of the EDS at Hatch were generally accept-able. Several strengths were identified in the areas of retrievability of documents, monitoring of grid stability, self-assessment, and competence of the

)technical support staff. However, some deficiencies were identified including

  • inadequate unider voltage protection for plant operation under degraded grid voltage conditions and inadequate coordination of short circuit/fault protec-
tiov devices for safety-related equipment. Fur example: (1) existing set" points and time delay characteristics of the degraded grid undervoltage protection relays did not adequately prevent accident mitigating loads and control circuits from being operated with insufficient voltage in the unlikely event of a postulated accident, concurrent with degrbded grid Conditions; (2) a 50.59 safety analysis had not been perforhied to evaluate the effect of load additions and tap changes to the startup transformer upon the undervoltage relay set points; and (3) overcurrent fault protection relay Settings on several bus feeder breakers were not adequately coordinated with tVL fault protection on downstream.breakers to protect against a ,otentitOlTs of an entire safety bus before local downstream faults were isvlate,.

.,D D0C:K 0500321 GD

August. 22, -1991

."2 -

It is our understanding that you (1) have -implemented interim administrative controls to protect the plant from unacceptably low undervoltage grid condi.

--tions,;-*(.2--have--Coordinated-ihe overcurrent ýrelay- settings- on -the-EDG-output breakers with downstream breakers, and (3) are in the process of evaluating

-corrective actions for -under voltage, grid :proteUction and potential miscoordination of other installed ctrcuits.

The inspection findings indicated that certain -activities Were apparently not conducted in full compliance with NRC requirements.. The deficiencies described in the enclosed inspection reportwill be reviewed by the Region 11 office for any enforcement action. Any-subsequent actions will be taken by Region It.

In accordance with 10 CFR 2.790 of the Commnision's regulations, a copy (f this letter and its enclosures will be placed in the NRC Public Document Room.

ino tisn~ ispreiquffed to -thls leTWer. Should you have-any questfdhs concern-ing th-is irspection, we will be pleased to discuss them with you.

Sincerely, (ORIGINAL SICNMf BY SL'9VEN.A. VA1RGA)

Steven A. Varga, Director Division of Reactor Proýjects, I/Il-Office of Nuclear Reactor .Regulation

Enclosure:

InspectionReport 50'-321/91-202 and 50-366/91402 R4:f1 111 11 RSIB;DRIS fSB I ASata~f PJFi-l1io~n LDWer~t SSandersl )U,'~N~rr~

0840u/91 08/;? 1 91. 081 _ 08/,1/91 0'8/'-V.91.

4.-C:RSIB:DR1. C"RSI B.:DR. S OIWIS :NRR

ý50P11orkin -EVIntro 9KGrimes

-08/1..V91 08/0-W 91 0,,91

t.-. W.G. Hairston, I... - 3 - Edwin 1. Hatrh Nuclear Plant, Georg Power: LCompany .Units Nos...1aInd.2 cc.

Mr. Ernest L.I Blake,. Jr,.. Mr. R. P. McDonald "Shaw, Pittman, Potts and Trowbridgt Executive Vice President -

ý2300l-" S-t-et. i N.W.. -- _- ` .Nuc*lear Operations

.-Washington, D.C. 20037 Georgia Power Company

' P.O. Box 1295

it, J.
T. Beckham Birmingham. Alabama 35201

',Vice Presidwjit - Plant. Hatch Georgia Power Company Mr. Alan R. Herdt, Chief P.O. Box 1295 Project Branch 03

.Bi.rminghaw., Alabama 352C.I U.S. Nuclear Regulatory Commission 161 Marivtta Street, NW,:Suite 2900

Mr. S. J. Bethay Atlanta, Georgia 30323

,Manager Licensing - Hatch Georgia: Power Company Mr. Dan Smith P.O. Box '12.9 . -PIrogram Director. of Birmingham, Alabama 352N Power Produc'tion iMr. L, Siililner- Oglethorpe Power Corporation 100 Crescent.Centre Ge;ira-l Manager, NuclearPlant Tucker,(Georgia 30085 Ruute 1, Bux 439 B).Iley ,..Georg ic ' 31513 Charles A. Patr.zia, Esq.

Paul,. Hastings,ý J-rnosky..& Walker R.sident ,nspector 12th Floor.

U.-S. NuclearReguladtory Conmi.iss.ian. 1050 Connectict

"-Washin'gton, DC. "Avenue, "20036 N.W.

-. W .

Route 1, Box-7 2. --

TBaxley, Geurgid. 31513,

  • Regional Adihnistrttor, Regior. 1I S" Mr. Charles H. Wadger U.S'-. .Nuclear Regulatory Commissionr - Office of Planning and-Budget 101. Marietta 'Street, Suite 2900- Room 610 Atlanta, Georgia 30323 .270 Washington Street,:S.W.

Atlanta, Georgia 30334 hr. J. Le.onard Ledbetter, Director Chairman Environintntal Protection Division Applirg County- Coiunis5ions DepartmenL uf Niatural Resources County Courthouse

.205:Butler Street, S.E., Suite 1252 Baxley, Georg'ia 31513 Atlanta, Georgia. 30334

U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR~ REACTOR REGULATION Division~ of Reactor InspeLtiou1 and Safeguords NRC Insptctitun Rtpo1rt-. 50-321191-f"O0 Licer~se No.: DPR-57 and anid 50-366j91-2CS': NPF-5 Uu.cr.ket Nos; 5C-31'61 iand 50-3bC LictioseE: Georgio Puwe-r Compnpiry Pficility Nai*;e filtch Nuckar Plant Ui~ts 1 and 2 Inspectiurs Conducted: Junte 10 through July 12, 1991 Irispectiun Teamh: A. S. Gautam, Team Leader, NRR P. Fillicn, Reactor Inspect.r, Region 11 L. Wert, SRI Hatch, Region II S. Sanders, Mechar,ical Engineer, NRR L. Tran, Electrical Engineer, NPR NPC Cw*,sult=r*ts p;. Leung, Atumic Energy Canada Ltd (A'LCL)

Lyles, AECL P. Maggio, Engineering Planning v~d Mar~agemien ~t (EPP)

L. Guntt~tr, Brookhaven Ldbs Wc'.g, Broukriaw~ri Labs Prepared by:

AnimI 5. autal,, Team Leader T1eaiL. illspectior Section A Special Inspectih, Branch Division* of Reactor Irspection and Safeguards Office of Nuclear Redctor Regulation Reviewed by:

Do7a6d Norkin, Chief ffat e TIeti inspection Section A Special Inspectiun Branch Division of Rtactor Inspection arid Safeguards Office of Nuclear Reactor RegulQtion Apprtuved by:

Eugene i.ru, Chief Special. 1nspection Branch Division of Reactor Inspection and Safeguards Offict; of tuclear Reactor Regulotiun 9109040298 91092 PDA ADOCI @P0O I 0D

LxECUTIVE

SUMMARY

A Nuclear Regulator2y Cowmilssi r. 1

., tean. conducted ai, tlectrical distributhi...

system functiural inspection ' ', I at tht Hatch hucl]ar Plunt Units I and 2.

The inspection was conducted b. e Special IIispection eraoich of the Office. of Nucledr Reactor Regulatiuo (NPRI:i from June 10 through July 1', 1991.

Thv NRC inspectiun team reviewed the desi gn ana desigli implerietatiort of the plart electrical distributioti system (EDS) irnd the adequacy of assucibted ergineerirg bnd technical support. To accomplish this, the team reviewed the design and installation of electrical and mechanical tDS equipment, reviewed.

test programs and prucedures affecting the EDS, and interviewed appropriate corporate and site personnil, A number of strengths were Identifiled as wtll as several deficiencies.

For the sam:ple selcted, the desigy, and i0stdllatiOn of the EDS at the Hatch Nuclear Plant was generally acceptable. Engir,eering calculations and other desigr documentation for attributes of the EDS were retrievable and verifiable.

This was a strength compared to other plants of the same vintage. In most cases, enginvering calculations had assumptiors and cOnClusions that were technically sound. Analyses for bus tronsfers were generally compreht.nsive.

Ilechanical systems were well designed to support the EDS. There was ar, eftec-tive test prograim for relays ard breaker&; the program included testing beyond the requirements of the technical specifications. There was an aggressive program for the configuration control of fuses. Key staff support from various departments was sufficient in number and the engineers were knuwledgeab.le. The licensee's efforts to monitor and maintain the grid voltage levels-irproved, the cverdll grid system stability and increased the reliability of the offsite power..7 to Hatch.; A design-basis indexing project for drawings, calculations, and specifications was a strong inifiative to further improve the control of design basis documentation. The substantive findings by the Quality Assurance (QA)"

group indicatud an aggressive self-assessment effort. Good interaction between engineering and other technical support disciplines was -evidenced by the licensee's responses tu safety concerns discovered by the team during this inspectionr. In most cases programs and procedures were well tstiblished and.

controlled. Good housekeeping was observed in the plant. Installed EDS equip-merit Was found properly labeled and appeared to be well maintained.

The teairi determined that under postulated degraded grid conditiurs the setpoirts uf the undervoltage relays on the 4160-volt buses were too low to prevenit the voltage on the 600-vult and 208-volt buses from dropping below the minimum rated voltage necessary to power safety-related -equipment relied on for accident mitigation. If the voltage on the essential. 416C-volt buses dropped to between 3`786 to 3675-volts the undervoltage relays would not act to.

transfer the buses from the uffsite to the offsite power suppl). Accident Vlitigatiieg equipment operating at voltages below 600-volts could have failures.

If the voltage or' the essential 4160-volt buses dropped to between 3786 to 3675-volts during an accident unider degraded grid conditions, a bus transfer.

would not take place from offsite to onsite power supply and insufficient voltage could cause accident mitigating equipment to fail. In addition, (1):thv.

CV-7 undervolt9eg relays used for bus transfers had time delay characteristics i

that. cuuld cause vxcessfve. deldys .befure thi bus was transferrt~d to an alternate source of power antd (a); Under' degraded geid Corlditiotis, the operators' did 'iot. .

get' ar. arnticipatury alarn, before the transfer of essential buses to an alterr,ate source of power. In rtsponse to these NRC concerns, the licensee implemented.'

pronipt adminifstrative cor.trols, including initiation of a 1-hour limiting con-

-di-tion- for -vpvra-t-i-on:-(LC-O -if -the- rid vol-tage fe l below 233 -kVs -(-equILvd-lent-.-

to 3786 volts on tho 4160-volt bus). If 'the voltage on the 4 160-volt buses cannot. b.e restured abuve 3786 volts within an hour, the new administrative contruls required. initiati(oi of dnn orderly plant shutdown. The NPC considered these controls. asu "interih" dnd wus reviewing lunner ternm.corrective, actions with the licernsee.

Although load additions had been made to tht EDS and tap changes hdd been made to the startup tranisformer, the licensee had not perforrmed an arialy*is required by 1U CFR 50.59 to evaluate the effects qf these charges to the undervoltag=:

rtiay set points. Lack of such dy) analysis may have cuntributed to the poteri-tical 0 insufficient voltage for the 600-volt level and below buses.

Therse was incorrect coordination bVetween thc fiv'e EDG .uutput breakers tha't feed" essential 416G volt buses and their correspondir,g downstreim load breakers for Units I and 2, resulting in a potential loss of an, entire 4160-volt essefitial

.bus during a postulated fault oil associated luads. The licensee *took prompt action in response to th! NRC coticerns by correcting the protective relay settings for tht 4160-vult EOG output breakers.

.Coordination calculations for pre-engineered fault protection config"urations for 12.0-Vac and "254Vdc control circuits were dtficier,ot. Certain conrL~iriatiors of relays and fuses that were app.ro.ve.d for. installation. permitted feeder breakers to essentidl buses to trip before the .downstrea.,m breaker or fuse isolated the fault. Field irnplemertatiorn of thes.e approved combir,.ations coulo result in, irccrrect coord irationL of the install.p 120-Vac and 125-Vdc 'circuits. Although the licensee was of the opinion, that these fust/breaker configuratiuns had ihever betr, used, the .lictrnsee agreed to review tht plant configuration and corre.ct airy such comrinations fouid iii the field. Di-screpacies also existed in the format otid inethudulogy of various cuordinatiun calculations. The team concluoed that.

the licensee should review coordination study calculations for the EDS circuits to address, as a minimun, thL discrepancies identified by the team.

Deficiencies iti the urdervoltage protection and the coordination of the fault curre,;t protectiui, itdicated that inadequate design reviews had been performed in those areas. The following ittuib dlSO require licensee actioris as follows,

(I) veriflcatlor. of the capacity of dn inverter to si.mu-ltaneously start and stroke three residual heat removal v.blves wi.thirn"Lhe stroke time requirerments of the technical specifica.tions, (2) revision to plant technical specificatiOns to accurat'ely reflect the bus transfer f unction of a set of CV7 urdervoitage permissive relays, (3) adnministrztive controls to prevent an overpressure condition on the shell side of the heat exchanger for the emergency diesel generator 1B, (4, various enhancements and corrections to design drawings, calculatiors, and the final safety enalysis report, and (5) revisioni of the EDG remote. shutdown procedure to ensure the EDGs w*re operated within their ratings.

TABLE -OF CONTENTS

.pal EXECUTIVE SUtJ 'IARY V v . . .... a .of .. .. t o 6.0900-f .

I. 0 I TR UCT-ION..... .... a 2-.0- ELEC-TRICAL SYSTEMS. 2.

2). Offsite Power Systen .............. * * .... . 2 2.1.1 Degraded Grid Undervultage Protection ................ 2 2.1.2 Load 22ClasI Increase 4160-a and Change Syýýp ... 0f Transfurmer Tap ......... 3 2.2 Cass -V t................. .. 4 2.2.1 Fast Transfer Permi ssive Relay...................... 4 242. Z ED6 Remote Shutdown Procedure...... .......

2.3 Class IE 600-Vac/208-Vac System .............................. 5 2.4 Ct'ass IE 126-Vdc and 120-Vac Systemns and COC-Vac Inverters.. -5 2.5 Protection and Coordination ...... . . . . ....... ....... .....

" 2.5.1 Irrcorrect.,Coordirrattion uf thle-EUG Circuit gre'aker ... 6 2.5.;2I Coordinationi of. 1-zO:-Vac a66 125-Vdc Circuits',..,.,.. 6 5-.5.3 Qls.crepariCies ir 1 Cdordi.iiatib C.91culatior.s.,,.,.,... .7 4.6.6 Cunclus s.or ............ ... . ... . .... . .. *....... ' 7 3.0 M.ECHANICAL SYSTEM S....... . . .. . ..- ,:. .4 . . , ,-,., .........

4,,

a . .. .. #. ,, 8.

3.1 Heating, Verntilating, and Air Condit-ioning System.......... .

3.1,1 High Ambient Temperatures for Battery. Chargers ........ 8 3.1.2 .Discrepancies in Mechanical Design Documentation ..... 6 3.ZPlant Service Water. Sy stem .................. ..

3.3 Conclusions...#,b!... .......... .. 4.to t ... 9 4,0 EOS EQUIPMENT ...... . 9

4. I Equipment hialkdowns...9 . . . . ... . . . . . . .

4 . 2 Equ i pme nt Mod i f i c a tK s. . . . . .. . . . . . . . . ...

4.3 Equ ipnent Testi and Calibration. ..................... 1.

4A4 Conclusions.."..........a 0 6 a. 6 6 a.. I.

10

5,47-: G~aNrCLRIGr AND TECHNICAL SUPPORTE.e.e..e.#41.0 6.kuwawre a.11 EXI l6n&tTN a4E .&.,f .*. .. .. ,, 0 &a*.... 9 #A.*e*.. 12 Apen4r t in Optfati.. ~8 12

1..C1 INTRODUCTION The Nucv ar :PFegulatory Confnýsnioin (N4C0 iitiated isispecttons of ttie efectric.-aY distrtlution system. (CD) at nuclear power pldnts because. previous NRC inspect-ions had identified similar types of duficierclse iii the EDS that could offect..

power suurý.es &nd equipprent. and 4oI7,prOMTSe pldat dtsigri Sdfety miargills.

r-ap'les' 6f- sddh defidencfes.'nc uded unnif-red and dnctiitr-olTed 'Toad goftlh-0,1. sdfety tuses and ir~adequato des!yn calrulatruius,. enyginter-inrg ModificatiurS,,

ur.dtrvofta.ý pr'vtectuot and testing and qualification of LDS equipfte't. The UPC corisidered one. cause of these dvficiercies to be i.adequate er',*rieerinr dand techtrica 1 support.

Thv ubjectives of this. inspection were to assess the adequacy of the Hatch

.Jlucler Plornt t.DS and the capab:lity and ptrfurradrmrmt of the licensee's engi-n.ering and techf.cal suppo.rt in this drea. For thv purpose of this inspec-tion, thw EDS ircluded, all emergency sourcts of power and associated equipnmert

.providirg power t* systems relied or, to remain functional during and foTluigwl.

design-basIs eventS. Tht EDS Cumporients includtd two offsitu circu~its fromwr the

.230UkV of-.ste power grid switchydrd, fivv emerqenic, diestJ gereraturs,: .1f-Vdc..

-:Class IE battvries, distribution trar*sformers, 416&-Vuit switchgear, 600-V4c load centers and nMutur control centers, 208lZC0-Vac and 2f./12ý-V'dc distribu-tior. panels, tattery chargers, inverters, breakt-rs, .rel3ys5 and Gevices.

The tear, reviewed the odequacy uf e.mergency utsite and offsite power sources for ESS. equipfirit, prote.ction for undervultcge conditions, the eluctrical loiad stud) ard regulation o.f voltage to essertial loads, pro~tectior, cf EDS equipther.t.,

  • avd 1uads from pos.tula-ted faul.t currt'Uts, and cordinat:ior, of the interruptltig
  • capa.tility of protective devies., The ted.rtLalsuO teview, d' mechanical systemns

-supporting tht US,: *incluOirig air start, lube Qi 1.,. arnd cooling .systeims fur tht

-,.ergerýcy diesel getierat-o.r us wel t as cuulii,@ and he.ting syster-, for EDM

.equipment. The team verified nametpate data and lucatior-sof itstalled EDS

-equipment fur confurmancrc to ýonfiguratlon cortlrtOl and design ducuments and

.revi*wed equipment quallflcdtion teStirn arid calibration records. It asstssed the capability and perfurmarnce of the licensee's engineering and technical ,

support functions with regard to the EDS, iindluding orgar, izdtiotm and key, staff ,.

t inw-ly and adequate roOt-couse analysis for failures and recurring problem.s, ard erginetfring irvulvenert in design fiL ficdt1rhd and operations.

As part of its dsstssnient, thc ?*PC team verified EDS desigrn conforrarnce with Generel Design Criteria (GDCi i7 and 18 and appropriate criterid of Appendix. .

to 10 CFR Part 50. The team reviewed plant technical specificatior.s. the 'ial safety aralysls report and satety evaluation report, tu verify that technical

ýrtquirements anr licersee conlritents. were bei-g mnet.

The team has clardcte riztd thir firdir~qs within; this report as deficitncies, 6.ind unresolved ite:,. and ubservatiuns. Deficien.&is enve.lop the dfir~itivr,s of both deviatiurLs drid violatiuis ir, MRL Nnual Chapter 0610. lhey are either

1) tht failur"t uf the li.censee to cuiirp)y with a requirement {violation) or 2) the failure, of the licenste to satisfy a wiritten LUMnitment or to conforrh to the plcivisiohns of applicable, codes, standards, guides, or accepted industr) practicces, eaCh of. Which has not been made d legally bindliig requirement (deviatiorn). UnreylsoTv.d items inivulve d concerr, about which nrure inforriation is required to oscerta81n whether It is acceptablu ur deficieut. Observations

.ae~e tss5uO~ GonsideeIed 'appropr1ate . u .6611 -to, Niefsee ma1nagiment atten~tion but-

-Whtt.17 havie OU app~arent regu1latry bo5si.

The areas rey -itwed sr4 the~ safety I~i9 kocr.re of identif ied deficiencies are Aesr.1iSed At _SL lgn 4 .1 . and4 5 of t~his ..rt4rL~. C.QrJQ.ions ate provt t4 -

at the tend oe vaCh of the~e set~tiuns5. Qeta i I uf the ftarnd ngs ore proy ided in,

.Appeiidix A with a Cur resputrdit9 number arid a reference to the Section of this, report" in 'which it is. disctusse'd. A list Gf_ pevsunnel co'rtacted is Orovided it.

Appendi;- L andi persoris attending the ext. fxc-tinig are indicated 'With dfl asteriii before their naines.

2.0 ELECTR;CA'L SYSTEM~

  • Tht *Lvdr: reviewed a smple? of bperi~fic electricdIl dtsirn Ot~trit~uteg at e,0 voltage letvu of the ~This. inclvdvd verifyincj the~ reliatility arkd ~,tatility

.fthe *offs~ite ýgridý pU~er, PIVnt 1~dd flculations for the regulatiun, af V0ltage tcu tlectv'ico1 Tuais nueded for tht 5.4e shutdown of the plant. unde,'-

--volae.t~p~tb far ~utrsxt~o txes, orcvrr~wrt prvttrot t~onclukula-r# far short crc~uit and gruund faults,. dnd the soz-fng an'd mordinatiot, uf' protedt~ivc Thef tear. reviewed d i~unttber uf ducufrents, rellted Wo iu~dd, aS .cidte4 Vairtr the EDS. Tht docuraents reviewed addressed. dL~an ca1kultiuns for 4C and dC.syste7t loodil9q, voitaqt. regulatior~ durinyp niorr'fA, and degra.ded conditr-ios, voltagw r)-L;It~Iot' durin g sequen~cing Wl sfty-r~erlted Ifiads pritu- the emergenL.) 4tes.4-1 gE-nerator$, -kELDCs., degrdded. voltadL- rtky s.t PoinS Class IE battery selec-

.>tion,.shtirt~-crcuit iin'dgruUrio-.fault. aflalys~is, prote~tive device cvvirdivfatiurn, end~ the pecitecticirý Uf :trhs. EtS frum puwter ý.rges. the team dlst; rtwitiitd diesiqr.-bash, doruments 'for th* EtDS, PrULdures. an'd cw i~ries. gvrning~dt.lr calcIA6_tior,!b, design c~rrtrioi avnd playv., mqdificution-s, 1 reports ovi ED& qual1ifi4

'Cat-ion .testsý a, systet: voltdqges durtnq degraded voltdge Conditicmvs.. arnd E&

single-Tinenietic.~ and prorteý(1ve relay setting dt'dwitigs.

2.1 Otfsite Power Systlerii The Ocf'site power' supply ýyStw- at WOt~ Nuclear Po~wer P;6?t consisted of' fout 4%00kV and f%,ur 23G0-KV trans~missict. linles cvni-ected to the switchydrd. !he 55(

ai~d 230-0V lines were ir~tercunn~e~.tCd by three :ý1n~le-pha~e dutumri~ti trdns-furmt~rs, Undtr nurmal opertotiuig conditio!is, all station non-safety. loadL wer~e powered b,>the 23C-k\4160.-V ullit auxilidry transfortitrs (UA-i), atd .4ll the7

.Class IE luads wiere powtued by tht 23C-k.V/4j6C-*.' start-up "iviliary trlinsturm~ri (SATJI ID anid IC for Unit I ara SATs 2tr and cc fu~r Wtrit Z. The SATs receivtd poWt'-r fromr the ý3C-kV switchydrd. Twu ildepender~l uffisote puwt~r supplies werie availIie for buth Patch units.,

The team,Ihott-d that thu VdtCh swiitchryard voltage level's be~re tlos~e%, ousnitured anid rtiaitinta. This effort wus primnnrilly perforri;Ld at the S.uythiev'n tlectric Systeri Power Coordinatiurn Ceiter in birminghdm, AlA~uiinw. 7he systeir coordiru-turs' If this. center courdinated the power: tra smij1sson ar,4 intetfaCed with tht crintrol centers. of the tiperatirig pltiits Iiicludint Hat~ch. The coordinator 'Was

  • .prirnar-i-ly- respornsib-le -tu ertsure- eff-icitnt- operationl V-- the -fý-teflt by rout ing-

.the various un~it~ atd. ridtChing power gerieratiui.S to. Tudd drrands.. TN. Ss~stem cour~diiators 4; Birwitigharrn performred cuntingericy.ernalyses, on the OVE-ral 1 sy~sttem

ýb. Postulati~ng lcS,s of .cowtratim'r ofr ItT&, traiisformvts. or Wmeiratursit If

thi rt.-sti Its of the' crtingency aralyses tn4*Lcfted t~t ftw preset ton iq*ra-.

vicold146t dCtior' to pfrtelud4. the- put..eol1al Probleri.

4.1.1 Deivrdted Gri-d Ur~trvvt,&1t-q ProtetiLtor.

A 9qtWYt1 1lTter titltLc: '[Jv9radLdv Prutectivy for l. Vowir ystn,

.issuv!' u) NPC on June 2. I9' required~ two lrvtý,~ Vf wuntrvtitge protectfoin, huss of volto9ý artd detrgidtd voltdge, ttj tnsire that drcidea sl~tit atinS loads htattirs) wc,uld: pe~rfolrN. thelf Safety f,utictiou.. Tht ýurpost: Vf the deigra&u.

voltage pru¶ectiogrr wi,! tu pre~clude~ th~e adverse effertý Lrttisd by sus.teirmt8 le grid Voltagk C1.I4dittons LIP th~e Closs ML lvadsr. Tho Serreric ltttt-r 4,tdt*4 thipt.

the unde'rvraltge srzheý* stlect vrnt,ýut~eagrr d time dela) %et pormts, Lased ca~

,dn bndl)'sis r., the VOI!4~t *tr.#1rkerts ISOf tihe C1634 ;j )WdS! 9t All ursitt sySteti~distribijtiovp ltel~s,. HuMIAver, at Ratch tht degradedi grid unerifvultodge prolect imn was riot. &dequate for tht- safe oprdt-ioP of Class 1E kwds ~at tht WO-'euIt. lwvtl iind below.

Four West irghou~i ty pe CV-'r'eId nas, hoawuiv~ timw-&lay fvaturts ve-t used to Protect again~st pLuteVtiai, CdilureS of tld'S IL acridcvtt etittiqatiN equ.ipo~iitt duritiq degraded grila volta~e torditions. ~7im of thLt,.e re-lays pr.v idtoa dow anid the* uthe r twu triarsfe-rred the busts. tL at. alterr~att poweV sm~rciE duriit' iý sustd'lr.La ateyadtd Srid volta~t- crdititu?.. Has*ver, .uiaring 4.ar-0~dept,

.tecouse. of the low settir.gs of the CV-` rlAdys., if the 416,7-V bbt5 wiltgai. bie qde~rd~Vr andf remained tv.4weer, d Vtjltot bid .b-Vt~ tt7t. buti i32.,

travs~ttr. toa the EDtis would nut bm~t. plorte anrd .14 Eldss, It IhjAts at mcltage letvds. of 6OC-' V itvel arod tehuw. Would Ltu rvce1-t su.ff icitrt vuoltage tu perfurar their s,;fety fvnc.tiofls.

In additltiti,, thie CV-7 degrid~.o VU~tade. relays had o t'ii& aelay 1eatuvi? that LQUIdh LdUSe excessivt delays in the trarsftr ojf the. 43t-V' bus frcjr t~he' oV'sitt, degraded grid to the a Iterviate, power spp:). 1he tim-voltage 0draitter-itirs of the rL'ldy indicated that OtN licenste vois relying or, the. actuo ticn, of the relu) iii a ranqy: uf oper'atior. thdt was uutside the range of the, Perforvitace curvcs supplied by the vtnd#4r. BaSed or. thL-st turvs, the teat to~cltudta V0~&

time' delay for thre CVdI tindervcoltdge to actuite bretwer, the. voltage tarid of 367E . V to 328C-'ý tyi the 4160-Vult bus, wik indeteru1ti.&atk.

The lldtt-rsee stited that if tht. switchydrd crid vo~ttk. waiý degradirg, the

,)epi courdindtor in EirmirngN.Ir wruid infurý, theC Hatch shift supervisur by Awltpht~r Andi take ir#*dih~ae ac~tlc to boa1t tht valtagit throug~h variu.us

.xont~rur1s. including~ eneroizir. 3 opariitwr banks, jrd addirug'puw~r throwch mr stiqtI

.of gel'troLing units. Amoever, ir,.suffmi'er0 aulinristrative controls exis~ted fat

.such actions and VtIE autwnatr uridervoltage prutectiu?ý was not *dequ4te, 1c, tiitigate tht. teem'!x ciunctrns the 1tcer~skte prurtly implemkited adblti~s~tra-

.ive- controls which Armdoded iritt?-tiun Of d Qort hour lioviting cond t io of uptrvatiut- (LCO) if' thtLurid vorlta~t fell below IC1.3 pterent or 2'33.Kv (equiva-lenit. tu 3ihft.V on the 416t-V bus). basred un ttrse toiotruls, if the 4160-vult biuis voltdSE cola riot be restored withu. on MAIP ta aboei 91 percent ur VU

-an oryderly pdartt ihutdmow wmI6 be.~ initiated. The Of~ fs reAV~eIA01 lthese aditinistrativt crcntrol4 relti-avt tv the eperabilit) tof the pwii-t. .;rd rco!id#j,'

4

Ing them Athterto controh' unltil futrher dt~cussion oith the i*Cerbste ~etgrd..

ing CA ny am crrttiv ocioQn fur tftii tn4ttio (see Apptnaix ht 2.1 .2 Load Increasse and Char9t of rrhre o

--Loaid grovttrl Ud~ caccorred ti, MPe NUMc rtituci Ter Iit EDS Coet tPo 'lost ter.

yeors. The totul pow requireme~t for sifety1 aind ngrm-5ifety iods after a

~LOV aCWdent1 tfl t 199.1 iiuItagt spUdy 91212K(Waa hitgher thadh the lciad it tht~

voltage study report subeftted tc tN W~inCI 19P4 forT underyaltaft prot~ction.

ýLtpatints. Ithe tt4m~ als~i noted that during9 tthts,.ptrlod the SAT ID tap posttin-

!ad disc teen~ Chdflged frgm 100 parcent to' 102 .ý percent. The teals covC1ud&4 that both uf theu above changes affected the voltd~e fewtis, of essential busts during deqradtd grid c~d~tions, The licenset could Act dernunstratv that a design rei~wew in, accordance With 1U FR 110.59 had been peffarned to eva'AWdE the effett ut these chwanges ant tht setpollitt of the undefvoltage protection, Therefcs'e the team~ Conctluded thal.

these Mang,r es shouuld hdVe WWI. etv 1u64ted to deteraine -11I ftay vilrewv iwed sof tt.

quietton NXIitf4. W;1400k of suchen evduautiur, Ry Rove ;Vnitributed to tbfe pvtentftiol for ifiddequtite vulte9es. W saet.y Tuodd (set: Appendix A Def fieacy Z.2 Class 'L 4I6C.Vac System The 41'6D-julot Class. IL OTstr' butid sys~tem v-si'sed of Oaksitt EDGsj pqwtr feett fr. the uffý4ft grid sivur~e, piuwr distrlbutI(4. equtpr-A aid c1fttit',.

tc, dcrtdtr.t ' itTitiri9 -loads.. Fivu V,4.tendeftt. EDCX.ý ptuvtided tris,ite' power fir Luh ftits, ot;e- EtIs ýfur *diN of the Nop saft~y Owivisors of eacihý uofit Anae

.thi.4 rswirts diestl ctould prov1ie back up. ptue ~'ettt At Eick 0, tft Mswa!, des~igned to providie emerguer-y ;awer to tt!1 te~pe~tIve vital 416C,-WYr bus. Thu~ 4 -1LVuflt bust*. -prhr ly -supplied rower 'for taN)-related punps and 60C.Volt hjaa renttrc. which in tu~rn pildvmak puwr to $A&] let eiectr-icdl loads. All safety buses were nurr-ally eneegited from thte effs.Ite grid# which was. cot,%i.dered the prtfvrrt~d 5ourcer of power.

Tht load capcit> V, tht EtLU4, jr-d th'e sizi. 0 the 1ota transfornwrs, were

  • adequote. Tht. load/current capabillties. of 'the 4CYotsafety buseso tables, and breakers wtre. adequate. the plant "b?1f.lte Slource voltaqt Stuay-19,91 thowed thet Whten tMe 2XkV WuS WdS Optrit~in wtthih its viorftl allowabfe vcltuge hic~its of 101.3 ptrcent. to 1CS.9 percerit, ~all the saftlty Io~4s on the at end di. buases would Qpvrate.

A~ll the safety-related mtors. when eurhnetted to -their associete4 loads, had tufficientf vultat ag nd torque tv aL-relerdtt; within ttheir. required startintg ttte.. 1*Vei.

ttt-motor with the lar~ges~t s.taitih tikit would not tm~e a Spuriuus trip or.r Ott 416(-Vtlt bus u.ndervisitage prue!Ltlon..

j.2.1 Fo- Ttiar~sfir Perei-sivt Wloy Luriirq under'Vultage Lur-diLiuTI!- the logic fur tlht. 41f6O-Vult bu~ers tra1nisfLrred the Lsserit al botes trum~ !AI it tt, RC. Pft~t1aeo 416040;t buses

-reowi~neoo t"46tuafe- for 11dit thdor one s.~iultG the~ )"iit transter5, the buse's k'4

.tv the EMkS. 'Pravil"Oy a set of CV-7 perm~issive' relays sensed underiicltage on

'tnhe SAT IC and. tfanrisfe~wed Powetr from IC tu -the EOGS.. Thuse permiss~ive relays

-A*f dgscribgd -M the Hatfet tintt.1w1csnical :Spettf tcatirans werer required to bar-

  • jIstdntdfieousti whten t~rdnsteretn -the bus Itruri the offs itt (SA1.1 to ansitte (ED)C suujrce. Howevtr, the iTnstdled reX~y identified tr the technical specification had 4IpjderltJ~yW fetu in v~infltct wtth the ttchnical specification require.

The ICe~rit~ov sratid that these ptirrmisstvo relays $dentif ied it, the technical specificaotion no longe~r transferred the 416C.-Vol', bu5 from' the o~ffite to onsite

.iwer because tft,.j had btfn miodified tv ur,ýy senSe Ondervdltaoe cin the SAT IC and Cmt~rul fts as.4or. ated -breaker'. The tror~sfer to Oflstte power Iwas currefttly Otrfhirmed bj dnOther set af rulays on the 4 16 0-vol, bu'ses thdt wou. d not be affected by tht perrosisvie rvIays.. The team had nou safety conctryis rggaralcs

?,ht ftutCion of thv resy however, the technical specifiCattuns did not tefl'ect

'the actug] plant conftguratiur, 'sve Appcfnd¶'x A, Deficiency 91-202Z-03).

2 2

.2. .6~ Reravte Shutdown Prucedure.

at a power fartur of 0.8 insted~d of M.~. This procedure applied to EDG la swn' k LA, an 2C. Since the aviid itistrumentittiur, irtly monitors cur-:

ruet,t, if the proc.edure ha~d btztn Jn.,.eneitted, *the EOGs could hev*e been rut. dt.arfl uutput higher than~ the hiaxiMura diesel generatur ratin9i, Tt correct. this error, the licensee agr..zed tor revise the PraCedufe to reflw~ )uWur Currenit ratitlgs based ur, a 0.9 power factor to A'.low -the diesel genrators, to stay 1hithijp the'ir.

c~ntnr.ousafl rdifl t-dp9.sei Apptnc; ix A~ t'efkcienc 9-402.C04).

.2. 3 clah 1 [s (£GC -VadC/20%-Vd SY Swre Thet~ able Vu",g dro'ps d'urf.ng the 1stirting. and runniing of 600,-V Class IE

.mturs werz adeqaute. The tr'ipCol s dfld.~~tor overltoad heaters for the f CQ-Volt CIbss IL viotor operdtcd. VE4%ts (.MOYS,, arnd. the length arid SZL Cf the cables ccr.rectirý Lhest' MOVs tu the motur cuntral centers wtre cd~deuete..

Preveritive Ptaritenance prPtvdtre,!. for thermal ovterlud~d rtlays and moldcd case 6irc~ult bre~~kers., and for the '%elettion of power an~d rontro'l cLableS indicated ro def iciw?ýOes.

2.4 C~lass It 1?5.Vac. drid 12U-Vac Syste*.is ar.c 6r0-Vac. Irnverter-3 e rftg drop and short cirLUl?. CalCUh~t.iUns fojr Utrdc distrikjtiurn sysiteL 4i.,4wed that (1) tht as~sociatt-d equipmert allowed adequate voltiage to assuciated 1cads and had adequate protectia'n, for prostulatea fault curretrts; (2) the i2r-Vde contrr.1 "ciecuit.ler.9ths 61 'dnot compromi'Se the entrgization of the closrug coils used in the contrul circuits, of tht 4.1(i.kV arid G00-V circuit bretikers; j3) the cwdntul between tht iristal led fusesý at the switcflgeer and the dr. distri-butior pof~elt did tot cause a ICS~'s of a Class 1E bUUanid associated accidebt rnitigating load!, during prustulated fau. 5 lt currents, and (4) fust ratiriqs wer properly Selected tu siistaifl the Starting rcurrt~nt. of the charg .ing mutor and to upett the cirtuit in case of postulattd short circbit faults.

Tht substdtiror, Lutteties wtre !sized for P hours, of caiitinuout. load, and the~

a5cit~-Lattery, charger was ýizttd fur iUChours, rechar~vg'i ti~e. ' The battqfy -

ano battry charger sizing cdlculatfons included design margin, temperaturt currection, add aging factors. The station batteries and battery chargers appeared to bu capable of pE-rfurming their intended functions. Data for the minimum required wvltag*s for safety.related loads on the Class IE dc buses showed trtat 210.4 wos adequate to operate a1l the safety related loads, HowteVer tho t-ean observed- hot 6600N01t fnverter R44-S0O02, provwding power t*-

four MOVs it. Division I arid. inverter P44-SO03 pruviding power to five MOVs In

-Division 2 Mdy not hdave ddt~(qte capacity. During an accident each inverter load included operation of the residual heat rEmoval (RHR) injection, irinimum flow, and recirculating pump suction valves. Under postulated worst c"se conditions each invert'er could bt required to supply power simultaneously to close the recirculatirg discharge valve, to close RHR minimum flow valve, and to stroke the RHR injection valve. The team was concerned because there was no 6ssurancv that the invrters would be able to provide enough power to stroke the vWiltS within tht time required by the Technical Specifications. The licensee agreed to perforr, ar appropriate LPCI inverter load test Zuring. the next refueling outgge to verify stroke time (see Appendix A, UnftSulved lten" 2.5 Protectiun arQ Coordinationt The teern found varictuS discrepancies with the adequacy of the overcurrent fauil protection (short circuit and ground fault) and Coordlration of protective devices foe the 4160-oid)t System.. Details are discussed below.

.2.S.1 1-norrect Cocrrination uf the EDG Circuit Breaker The overcLrrtrit protection relays iinitlatning a trip signal to Unit und 2 EDG d

uutput cirCuit breakefs wtre not coordinated with the protective relays for the downstream circuit breakers. If the diesels were energizing essential 4160-volt buses during emergency conditions,' a pustulitd-fault on a bravich feecer had the otkrtir.l 0f trlppinfl:the LOG outpu~t circuit breaker befure tripping the douri-strear; branch feeder circuft bredkers. The. team also fiote.d thot the incorrect coordination of the diesel generator circuit breaker was also missed by the licensee during its review of the Apprndix R fire protection study (IC' CFR Part WQ).

ThL licensee tuuk prompt correCtive action to reset the proteLtive relays on the EDG- output breakers during the inspectiun (see Apperidix A, Deficiency 2.S.2 Coordinatlun of 12G-Volt ac and idc-Vult .cCircuits Generic fuse coordiriatlun studies specifiea approved configuratiuts fur various oesiqn conditiuns. However, the teamf nioted several incorrect coordinatiorf% for specific ranges rf fault Current betweer. protective relayS on upstream breakers

-ano downstream ftse. Fur example, relay characteristicS on a time currert curve 1rditateo ttht the upstream breaker was tiot prcperly cooraiinated with a dowr,stream fus, over a fault current rar~g.- of 40 amperr4. These "approved-LonfiSurations" may hove resulted in the ftse* not bvlric correctly cootiratrd durigthe.upgrade arid. replacement progra=m,..

7

-Over $000 fuses had been reviewed to date 4nr'der this fuse .pgrade amd replace-ment program:for UUhits [and 2 affecting numerous 12C-Vdc and 120-Vdc circuits with breaker/fuse configurttvios. All prw-engineered- breakerifuse- cunf¶gurat E, should be checked to..verify correct coordilntion. Although the licensee was uf the opinioh thatthe Suspect ombindtio, s had iever been used, the liceriseE.

dgreed to review guneric fuse coordination studies and installations for errors (see Appendtx A, .. eficiency 91402-4C7). 7 2,5.3 Discreparic~es iri Cordinat1ir, Calcuiations ragmeinted doeumentatiah of cuurdindtiUn cdlCu1dtior, frr the EDS evulpntent d'td it very difficult to determine if the protection or the feedtr breakers to essential buSes was coordinated with the protection on drwnstream breakers.

This was hecauSe the Hatch coordination study wds fragmented, ror eAaMple, calculations created to implement specific uvercurrent trip device odMIfCa-tlotis had not been integrated with calculations of other related circuits..

Also, Appendix R calculatiors only addressed Appendfi R buses and loads and had not been integrated with calculations of other affected circuits. This approacm of sattsfyfing cooraIrattori for a sopcif t i.Todlf fatfon had the potential for error.

In reviewing the Plant hatch/*,eayl*ig Data Document, the team noted thbt the protective device time currentcurves were typical for multiple appliCttions.

Specific relays were identified on a relay data sheet that indicated relay settings and a reference to a :typical time current curve. Using .týese typlcl4al curves tould have caused coordination errufS becaube relays.usfng the same typical curve did not always Ptave th.same chIrnteristics, the cases reviewed, many ut. the time current Curves. had (o be overlaid and held to a light source or be redrawn to determine coordinatioi.i An errur could be easily made in identifying devices and analyzing Coordi.nation with these typical curves.

Although the licenseb haa a design guideline for the maxitmm setting of 600 volt iinstantaheous or Short-time trip dEvices for Coordinatioll of these devices with upstream relays, the applicatiun of this guidelirie was riot apparent in the calculetions. In addition, the title of a short cOrcuit study had been Chdnged to indicate it was a coordination study, however, nO changes wtre made to the body of the calculatiun to transform it to a coordiation sfudy.

Because of the above documentation diffi~ultits the team had difficulty in vtrifying the adequacy of the coordination of installed circuits. The team recommteided that the licensee review Cuordtnatiun study calculatiOnS to address

.aS a riitfimuM tht diwcrepancies idehtified by the team (see Observation 91 -202-08).

2.6 Conclusions The design of the electrical systems for the electrical distribution, system at Hatch Units I and 2 was geheraily acceptable. Tht capacity of onsite avid off-O1tt power sourCeS was uffitient fNr plant loads. Staff support Consisted of a sufficient number of engineers with an understandi?,g of the relevant technical 8

issubs .Engineertng :cocu Ia.ions and uther desigri documentatfion for attributes of the EDS were retrievable and verfitable.I In most cases, engirmeering calcula-

.tt~ons had. asswimptioris and cwinluSins- th~at were appropridte.

lTheru werle sonre inadeqvraciue! in tht design of .sr;dervoltdge prutectton durirng degraded grid cunditions. Under certain conditions of uperation the degraded grid relay set point5 had the putentfal to cause failures of accident mitigat-trig ft-S-equ ipr Ther-e wero various df itencitfs retdred to 'the coordination of-

,TtJ-fault prutectlvý devices, ds discussed intSection 2.5 uf this report.

3.0 ,C.4AN ICAL SYSTEMS The Ceamn translated various mecltanicdl Tiads (selected pumps and MOVs) to electrical loads (kw) by exanining header pressure and flow punip curves to

.verify the sizes of electrical loads used in the EOS load study calculations.

For the samrplt selected the niaximun, pump motor loads used in the calculations were accurate.

Thr monthly, seml-ditnual and 1-month surveillance test procedures for the diesel were irn.accurda.nce with the plant technica.l Specificatiw(s,. The venrdo{

(CoIt industries) recorrinendatioris for the operdtiovr of the EOG were accurately reflered in the final safety analysis report lFSAhR and plant operating procedures. Tht last five-start test for the EOG was completed in accordance with the requireme.rts of the plant technical specification. Trei. fuel oil tanks wtye designed tc specificdtion and the licensee's procedure for monitoring and routine testing of- the diesel fuel oil was acceptable.

2.1 Reating, Venti!otig, and. Air Cunditioring.Syster,

Tht richanical equipment as',(.ociated w.ilth tne .heating, ventilating, and airt, conditioninq. ('HVAC'Isystem, was adequate to maintain proper ambient temperatures for the diesel generator building, battery rooms, and essential switchgear

.ruonos. However, there were certain discrepancies in the HVAC calculations'and documen tat ion.

3.1.1 High Ambient Ternptratures fur Batterj Chargers During surrwaer, high ain.ietit air temperatures expected in the location of the

.statiurt Lattery chargers had the puteiitial tc affect the performance of the installed battery £hargurs. The licensee stated that the maximum temperature during. the full-load operativi, uf any battery charger would be 104"F and that the battery chargers were rualifiec for up to 11OF. The licensee also stated, huwever, that, the installed battery chargers in both units would be replaced during the next outage to withstand ever. more stringent ambient conditions of

.135rF ever a 4-hour period durir;g postulted blackout condi.tiuns, 3.1.2 Discrupancies in flechanicil Design Documientationi There were stveral discrepancies it the rSAR anri the design documentation regarding the Ebb air starting compressor setpuints and operating parameters

.q-., l.ow pressure start, high. pressure cutof',. operatitg pressure, anid air receiver pressure relief valve setting. the licensee agreed to revise appro-

.priat&- docuR.en-ts.... ..... ....

There were ditsrwrvltes betwen the licenset'f cala culatticns for tie V*AC system afr fIow distribution. The air Co se-ir.-h,4 6eev.replaied1 , reitiltirg in dn everal1 Tower air temperature for the battery roms. However, tht c.lculatloni had not-beer. revised to $.how this luver heat load. Changes had been made on the plant drrongemtent drawin% but had not been incorporated into the P&I. .nd pres -f low _drw.Ig, . ..

Thi original lewd antimvny tatteries hoc bee*n replaced with. lead C.Iuoua batterits that had a Towryr hydrwten generatior, rote thanr the original bat'ertes. Howtver, the hydrogen generation rates in the calcUlatiur.s had not been revised to refiect the addttforaI margins-or tfne it would take the tnydrugcri to reach, dangerous or txplosivt condlltions on loss of air flow to tnt battery ruums.

Tie leter,see agreed to correct tte appropriate calculationr,s ond drawings (set Appenaix A, ýefictency 91-62OZ-09),

3.2 Plant Service Water System The secti~on of 'plant service waLer pipirg between the supply and return isolb-tion valves of EOG IB had the potential to trap service water in the a(sociatea heat exchanger. If tne hot heat excanger was shut down, the trapped flu'i could heat ,up arid expand and cause the internal'pressure to rise on the shell Side of the heat exchanger. This could lead to a potential uVerpressure condi.

tiuti. The licensee cummiitted to revising the station operating prucedYur to require that the operators mairtain Standby Service water flow fpr a miniv of 1112 hourtafter the diesel engine was 5ecu!'ed 41n order to eliminate over peessur&

coricerns (see Appendix A, Defi.clency 91-20.2-10;91-202.-10).

3.3 Conclusions The diesel generator and its support systems were ir, conformance with the design specifications for the EDS. Tec'hnical staff were sufficiently knowl-edgeable 0i the mechanical Systetr.s supporting the EDS. Calculations and test report4 were readily available and demonstrated a Sound technical basis, which wti considered 4 strefigth with regard to enginecring and technical support.

Licensee actiun is required. to dddress the Potential (f art overpressure conditlGn on the shll siide of the heat e~xchanger. Updatlii of mechanical design documerntS was a weakness evidenced by the discreparcies between HVAC drawings, calculations, and the FSAP. turthier attention to document corntrol and updating in this ared is recommended, 4.0 ED$ EQUIPMENT As-built configurations of selected safety-related EDS eTvctrital and rechdni-cal equiprient conforred to design requiremerts.

4.1 Equipment Walkduwn5 The E*S equipinert including supporting mechanical equipment confovtned to design, tequ.irenents_,. were properly labeled, easi.fy, ideritif-iIble, -and-aceessib-le, -Good*.

I0

hamuskeepihgq Was dppdtt't ti: Mt~pltant, ivrd the eqvtpr,rkt dppsttod No be v*T!

mdiotrit.'Id. The support stdtf wss krow~edgeaible. cc. ptcent &F~e tnuw.y 1r; driswertrt% question~.

Drawin~s kosed to fasciTitate the Wa~lkdocwns were Elteiv end troCeate. and lii-os Cd5Se eflected the fleTO c4onfiguirttIun., Soft dIl r~perwC1s, bwtvee,% i~)

th._-diMtnStr'.r ra svuii table troy WI1ptpe %ujrt were ifltcrre~ttl m~ttd or..

.tht drawingS. The h(er,see Cortrumed 9hot the cquiapmtent i" the IiW74 0;t

-assig fequiremerits W tht 'thest: drawiflgl NiA rutI beir. u;4ated. flit, Ncrens iSsued des!Sr, moeige notices (DEhst to currttt thtese docum~~t. errur% are to ImpTKinrt. tFle jiectssdry correcttvie attionr. Nl further', cofteVFs wert- idet~rife4.

Thte deSign evd'ivativn revieve and ap~r..v.I prioce~s was adeqult~artd toret.

Ovt drid MfC1~ded 5crtening modification re~otsts for reruired j ORCr..t?

.Safety e'valuatiorrs.

TPv *.j494wer;#" dtst" #& ftPTG tI*tcatvum cv*Er* prrjtexs w"- well proutrwglrumr, Cestgn Vfirigvg wtre reviewe otid apprtiv 0, aiccardairce with the tec~hni'Cal SpeCiffLaCtlori drid estdbl11sbd ýAfQ cortrots. The tictris'e cco.ducted '-

PijIfica'dttjaQf tesItS. an~d Performft test resu't evaluatluns before deelarinq tho affected rw l~einL afc systems upc.ratle. Kost test iesultý reviewed were within previously estatlhied accept~nrce cr.rteriij. the litense&t revieutd test result deviations 4fld wnere- cpplitibble, pErformed rettsting. the I leniee'15, precedures cutitrulitgi~~ f~t(, wor& and do~uithtatWo retords weree jenetriITry tanilettc an'd p h v.

4..3 :Equipmef.-t Testingarid'Calibratiori Tht IiCtnste had a well1structurc-d program in pl4ce foit- performing preven t~vee martrine surveillance, arid testing of 02S Oquipment aird Comp.onents. The prcogrdrin. acaressed the t,*stiq, of emivrgetscy diesel gErtvratQWfs and As~ociated syrsteft;s, trdrisfornitr5, 6iuturs, tjdttetteOS, cir'cuit brtakers, arid protective rclay'tnq. The prvewntive i!8intenan~t progrdhi was based on ven~dor teeourenda-Ltrts, and thfz suryefllurct ti-st~vc; was in aCtordancie with tht plant's tethri-r~al Specification ?eurequitmvits.

The Scope Q1 tht teý.tir.G and calibratiort program~ was adequatt. A Strons test prugram vat it. p'lect ?or rela~yS and breakers. Itsting wentt NyvvtiI4 the re~quire.

r'a*nts 01' the techntcal speciflI tictions, All sofetywrelated circuit treakers, irai1uding nirlde-d-cast brecokers, were t.4sted on A ptriodiC bas-is.

The wtodtrvoltagv rteyd instrunient. functiortdl teSt isrid Cal~lbratiern procedurts liidicated that the- "ruset" vultages, 0' Westinghousti CV-7 relayvs were Ufter less thanl the "pick-up" voltoiges. The licensee acknuv~wedged that the procv~eure was Iir error but. thtzt the Unit I procedured had lready beeus corrected, Durint~thte in~spectioi,, the lfter.stf initiateo corrective actior, for tht unit 2 procuiure.'

The error did nut result in arty adver-e~ effects oii the operab~ility of the 11

4.4 C"lusiots jwtVft~nencq and test pro9Fhe for te~ttFtca! spstmf sad io~~$ Tb&

frtqavicy of i',rtetnflUce are surveillat~ce art-C testtnq was adew~tv to wtf fu~nct ional p*V16'.&Mat(S.

5.0 MINECAMh AK` TECHNICAL S~ftk&-

The team assessed the capab~ility and perforr.mtt tf the lic.&rsets ur4Yd*rudttori tiv provide e~itriqtn anid technical support. Iftitt~iii elatda ~interfo.gS betuveft the tech~itial disciplol'qs fyvttrftal to the mtigtnttift9 orgdfnattobi 494 betiue~f the .e"Mgeering argaentzatt"~ &r4 the foctato~a1 tor"pi Pfrfarmiul design reviews, IFeld Wift IattIril Srvwtileditt@, testihkg. *Ed 641telletcir.

The team alsu. sxamined the working he~.tionillip betvwte the O"Site arfotat-~

tions, and the offsite SVPPqrt or~gAFtaatiotS.

5.1 Or~enizatton and Key Staff S'Q.tten Company Servtm 00 0i4 Secrtel W7 M artily r'ewo"fI~iI* Qtt -

itations pro~viding primar~y enginveri. g support tiu th* it-tch M., Bechtel muinftaineld at, orgavbzatl~o of ab~out 4(. anisiefs and i~thtsttteh1Wuj reparua to SCS. SCS and Sechteil weftres.Woftsble for butAtaiu4V6g the de'Ag. 9ai11iof

)latch and ftifltained orgaptiatiors of tevgifters dedicated to the sopp'drt, of Plant Match. !he ehgine~rS 05slghtd %Qtht 'fetch Prii.$et Wee SUff tC1ert 0,.

fiutbfit@' and exp-trleficed.

6.2 Rout' Ct~aus Anallysis and Corrnttive Act ,'r

'LERs, OA audits, anid other d uients indicAted tha.! the root causiv d"Iy~stl process *as adequate. Revfee (if 'ftwe LMR, iftdficied 016st tht everat r"eyt, re" fteeded to iden~tify Mwort detail With regard to the rpot cduiv of co~panevn failures, Por examiple the team .reviewedLt.R 321Y(11.0 and Aoted thott .h.

failure of the switchtyed breakt~r 179100 was ittrfbtted to the farlure if'a currer~t limitipg resistur in,the trip cir~ulttt. Nowever,, the ttep ifeteralfed that the resistor was ,;il the primar,) initietot.of the failu~re drd thet, furtftr ruot cause afialysis was ruquire1a Correctivt acti(oes in re-Sponse toi~ dvttIfied problesS wert cur4itdered ad"e~ut end reflected high-level mat-t~tg'fltn WPPcjrt of the licensee's S1rf-ussesstovnt orgarnizatiof~s. Ftor example, both Onsite ar4 SCS aui.Gts; SP'OWed thet the safety analysis-and engineering review (SAMk grouip had requoSted and obtaintd addi-tional ~Orc~thre activitl beyond that minttioT, 1 prposed Tif respwfse tu it firding. Ur, examples Cof Inlacegute.relpon&*& Oere hottd4 bmwe'ver, ir,stivvrai in~stances the final resolut'ion of SAU~ t~hatnq$:ur6 not. t11*1Y. tat ezxtile,

e. 1988 finding invo~lving~ breeker/r1163 trip testift9 w6S ihot rtsulved for, over 3 5.3 Stlf Assels5*ert abd Training 12

lr _r~gs t!pr _ tt e4.d s *0 8%Pts

'rovr !t'E*. rpfuiesr! two 0, tatru tit fwtetI.

, Itctwi S"tC.Mitfi a.

at{tw* rteer rtivrji,, ark w ortrkd FR*It)rtl,type 'Are setttr':

%ji64f&4utj,'ttgs.4t".tdil(

he. !ti*atr, Mts,wirrQ,,{.ted nt fltto.u pr, t ~ems f*(l &

tU~vf cr~"refefftr.it al It jo cr) .*fltnt tt.U#&Sg'M ~iiit. ras

' r e f.

r ,p rt t o r3

~~A~ :rostL %firtr~r spe~It

~twiu~swlt tt~tI dl~!! 1tflt~tt.4 014t sufttCietl ,Ntft a*f.Ce euistied

~tunt t i*?tcnset~,, *0Att& Ind cornrttt !.sP. Thit te40at blern w-riue'cqt tppr t 1ceer'.n CftMA-.t

.vf tf* tt'eesS*9ia diert.dIeajte ed -to OtU 14ps=v"t dtfls, hLa etb awjcFtel~nd senalp..

sg'*e. frit9Ih C&R*T, f.r~ulet tFI.ttr tfs tAkCI Vowtift-Si t, App".endi, or (ktwu.3rd~Pt$G-.~

Ctxýntrrs reiarglui, IN-

.reitr), q tr~

z C014 P tilt.LZ*6qutpf O.thce. w N' i t rn~ttfL to'tr~ek. a iftIjle u,

  • rzce-plq rmtr~terJ, tRLfttnVVh 4anshre4 t'*$eeeb ir..li de~etttI~. .tiF~ttta

~c~err kwc~.

cd itrt I suppott aireiI41.RtutheIN Watth pI.&1t.jpp;tsrtd.

adEutw ~mnctrt wtfti SOjjitminL ttet fru 04M aexpt r ieute. 14 ic".Stee rovetas eiasu gidccrruaiwt. aCt4ýu pto~raef .pp~eartd4 tit. sttoa 9 EýC tc LPtt " ufrGbtttd a r tjrt' SgEttiql 6f. .'Uy 1Z. I'M, it the Hettt huclear Prart t*ditw.,s the Majrrorettos ruviewt-d durhuig tht, nspcctust, the stretrrttM arm wetvfrvesses ot.,e-rved,* artd !;rdings. II* mda+/-&*fete frosNrR, 019a6 Regiuv, '.1 are tice-Askt 'reprcser.&tfJves sht* *titndta this M'ewi" Ort identified with at I.1btstk it,, AppehfdlP R'of this. report6, "The teat- dit)$C4e4 liter's,. OttiuL, it, majo~r intssu$ Th t: t~e rid hot, IdettWf *ry~ Cvtuaastrts. or rtctIetpi as 13

APPENDIX A.

Insptction Findings DEFICIENCY 91-kO,-C1 FINDING TITLE: Degraded Grid Undervolta e lel-y Setpoirt (Section 2.1.1 of repurt-UESCRIP7iUN OF CONDITIONt Two levels of undervoltage protection loss of voltage and degraded voltage, are required to ensure that accident mitigating loads (such as punp motors, MOVs, control circuits, fans, and heaters) would perform their safety function. This undervoltage protection is required by Generic Letter titlcd "Degraded Protec-tion for Class IE powcr systeras," dated June 2, 1977. The generic letter required that the undervoltage scheme select undervoltage and time delay set points on the basis of an analysis ofthe voltage requirements of the Clas 1.E

-loads at all onsite system distributior,.levelS.

Two levels of undervoltage protection were used to protULt the Class IE equip-neriet at Hatch. Westinghauuse type CV. 7 'short tire over or utder voltage) relays were used. The CV-7 relays have a time delay that is inversely prupurtional. to the diffbrence between the actubl bus voltage and the nominial bus voltage. The first level of undervoltogL relays were set tI trip quickly for a loss of offsite voltage. The securd level of degraded grid undervoltage relays wLre set tu alarm and trip fur a sistainod degraded system voltage con-Uition. Both levels of uon'ervoltage protection,drd their trip settings were.

  • iverf in the*technical specifications. The degraded voltage protection relays awere set at "1UM-V Tap" and "Mro. 5 Time Dial" and the relays were calibrated to

'trip ii, 1.' seconds at 93.7-Volts. With this setting, thk relays would start to

.pick up at 3676-Volts (88.34, of 4160-Volts) trigger. and at 3280-V (76.b.* : of A160-Volts) the reloas would trip in 20 seconds.

  • rI, their vu-tige study the licenset indicated that under the worst case opuvtat-ing conditions the 236 kV bus voTtaoe could be about 98.8 percent (227. k,). Th.e tram determired that during a postulated accident if the 4160V bus vultagt was
  • between an approxicate voltage band of 91 percent (3786W to 88.34¶ý (3675V)
  • .quivaient to approximately i01.1 percent or 232.5-kV to 98.7 percent or-

"227-kVs at tht 230-kV bus), the Class IE loads at voltage leVL*S of 600 volts arC below would not receive sufficient voltage tv perform their safety functions.

-The CV-7 degraded voltage relays had an inverse time-voltage characteristic that

-could cause excessive delays in the transfer of the 4160-Volt bus from the off-.

1itt degraded grid to tht alternate power supply under certain voltage curdi-tiors. The basis of this concern was the licensee's reliance on the the ractuation of the reldy in a range of operation that was outside the range of

.-performanct. specified by the vendor. Based on these curves, the team concluded

  • .that the time Oelay for the CV-7 uidirvoltage to actuate between the voltage

.Land of 3675: to 3280-Volts or, the 4160-Volt bus was indeterminate.

.The licei.see stated that if the switchyard grid voltage wds degrading, the

'System coordinator ir. L*irmingharn would itiforii, the Hatch shift supervisor by.

dnd take 1inftdialt tel Lphone inc)ud action to boust the voltage throLgh vdrious contro-ls., ing*ent!rg Zing capadc Ottr .bafks aid adding power through other generating units. The Ifitch staff Supervisur would then assess the condition

-and possibly reduce loads. The tedwn concluded thdt although monitoring tht grid increased the, reliability o1 uffsite power to Hatch, ilhsufftciert adminib-

-trativt- ctortrols ex.isted--for such- d(.Liuris, .. fld._that the. undervoltrage

-niati protection was not adequate.

To mitigate the tedn,'s 'concerns the licenste promptly'implemented administraitve' contrcls which included initiation of a I hour LCO if the ýrld vuoltage fell

below 101.3 percent or 211-kVs, If the 4160-volt bus voltage could not be
  • restored.withii the hour LCO to above 91 percent or 3786.Volts an ordarly piott shutdGwn would be initiated. The NRC is reviewing these administrdtive controls relative to the operability uf the plant and considering them "interim controls" pendiiig further. discussion with :the licensee regarding any long-tert, currective action for this conditiOv,.

Criteriur! 111' of 10 CFR Part 50, Appendix B, statvs thdt design contrul mea-sures shell provide for verifying the adequacy ofdesign, such as by the performiance of._desmigf, reviews, by the use of alternate or.simplified calcula-tiona; iaethods, or by the perforitance of a suitable testiirg progran,.

Ger,eric letter, "Degraded Protectioli for Class ,1E Power Systeris" (1HPA B03),

.dated. June Z, 177: required that the *selection of' the second level degraded grid urervultage'and time delay set point be.. determiaired from an' analysis of t.he Voltage require.mierits of -the Class lE loads at all orsite-systew distrlbu-tion levrels. " ' . .

REFEREN ES:

1. Geurgia Power Conpaniy', E.J. Hatch N. F. Surveillanhce Prucedure No.

57SV-532-002-1S.'m

2. Westinrhouse .Type CV Voltage Rklay Installation, Operation. Maintenance liiStructipi,-s.""

A-2

DEFICIENCY 91-202-02 FINDING TUTLE: Load Increase and Chan9g uf sW ID Tap (Section 2.1.2 uf repurt)

DESCRIPTION OF CONDITION:

Ovwr the ldst ten years loads had been added to the EDS. Thu 1991 voltage study 91212PG Showed the total power requirements for the safety and non-safety loads after a LOCA accident had increased since the voltage study report

's.ubmitted to the NRC in 1980 for undervoltage protection setpoints. During

'.this period the SAT Mi tap position had been changed.from 100 percent to IC2.5 percent. Both the changes affected the voltage levels of essential buses under degraded grid conditio'is.

The licensee could not demonstrate that a design review in accordance with 10 CFR 50.55 hiad been performed to evaluate the effect of these changes on the
se.t points of the undervoltage prote(tion. Therefore the team concluded that

.thSes changes should -have-been evallioted tu deterwine if an unreviewed safety question existed, The lack of such an evaluotiorn may have contributed to the potential fur ilnadequate voltages to safety loads.

REQUI REM.ENTS:.

Criterion Hi1 of 10 CFR Part bO, Apperdix B, states thot desigin control measures

.shall provide for.verify.ing the adequacy of design, such as by the performarice.

.of. design reviews, by the use of alttwate or simrplifiedcalculational methods, 6 r by the performance of a suitabl. te.tiing program'.

.1U CFR Part .50.59 states. that the h6lder of a liceiise may make changes iirthe facility as described ii, the safety.analysis report wi.thuut prior NRC approval uniless the proposed change,.test or. experiment involves a.change in the techni-caYlspec.tfications or an unreviewedsafety question.

REFERENCES:

1. GPC Voltage Study 91212PG, 1991
  • 2. Letter from R.J. Kelly to USNRC 'Office of Nuclear Reactor Regulation, dated December 7. 19S and under NRC Dockets 50-321, and 50-366.

., :GPC letter from W.A. Widner to USNRC Office of Nuclear Reactor Regulation OResporse to Request for Additional Infornation--System Voltage Study,"

dated October 9, 1980 and Voltage Study Calculation,. Rev. 2, (April 1980.)I A-3

DEFICIVIICY 91-202-03

-INDING TITLE
fast Transfer Permissive Relay (Section.2.2., of report)

DESCRIPTION-OF CONDITION:

During undervoltagc conditions the logic for the 4160-Volt .bses tr~nsferred

.the e-ssertia] buses from SAT 10 to SAT IC. - the voltage un 4160-Volt buses remained inadequate for one secoWd the logic, would transfer the buses from IC

-tu the EDGs. Previously d set of CV-7 permissive relays sensed undeevoltage un the SAT IC and transferred power from IC to the EOGs. These permissive relays, as described in Table 3.2013 of Hatch Ulilt 1 technical specifications (TS) were required to be"lnstantaneuus" when transferring tht bus from the offsite (SAT) to onsite (EDG) suurce. However, this relay hiad a "time delay" feature in cunflict with the TS.

The team noted that i.n April .19&1 a failure of these CV-7 permissive rtlays
  • durillg testing had resultea in a failure of the EDGs to energize the safety

.busts. After an LLR was -submitted, discussions were held between HNR and a

.lodification was proposed to alter the function of these two relays. In ithe interim, -Table 3.2-1-3 was added to the 7S (May 6, 1982, TS Amendments 88 and 27 voert approved which included Table 3.2-13 and the degraded grid and -undervoltage requiremnents). Thy nodification (DCR 82-34). was completed in 1983. The licensee stated-that these relays no lcngier transferred tht4160-Volt bus from' the offsite (SAT) to onsite (EDG) power. These relays had been modified to only sensa undervoltage on-the SAT IC and.control its.associated breaker. -.The.

transfer .function-was-currently performed by another set of relays on the

.4160-volt buses that -would- not be affected by the pernissive relays. . The tean-had.iio safety. concerns regarding the function 'Of the CV-.7 relay, howevee, the .TS.

-did"not reflect .the actual. piant.configurationri.-

.REQUIRI4.ENTS:

Technical Specificatlors- Table 3.2-13, Hatch Unit 1.

REFEREINCES:

1. Table 3.2-13 of Hatch Unit 1 Technical Specification.
2. Relay Lat; Sheet 40cof UW-17, Plant HMtch.

A-4

DEFICIENCY 91-202-04:

FINDING 11TLE:: EDG Remote Shutdown Prucedure (Section Z..2.2 of Report)

DESCRIPTION OF CONDITION:

The EOG kteptt Shutdown Procedure, Document Number 31RS-OPS-002-2S for EDGs IB (Swing)., ZA, and 2C, incorr.ectly assumed diesel generator loads to be runnln9 at 0.8 power fe(tor when in fact these loads ran at 0.9 power fdctor. In the procedure, on Itages 2, 5, 9 and 13,'a "CAUTION" to the operator stdtLed that the diesel generators must not exceea the ratings of 490 amps continuous and 660 amps for 7-day/168 hour rating. Based on a 0.9 power factor, these current ratings allowed the diesel generators to exteed the maximum kilowatt rating.

At 490 amps, the diesel generators operated at 3174kWs (continuous), which exceeded tht ZB50-kW maximum rating. At 560 amps, the diesel generotors operated et 3,627KI (7 day/.168-huuri which exceeded the 3250kWs maximunm rating.

Siric the available instruewrtation only mon itured current, if the procedure.

had bf-n isplement~ed tht Wfis--,coakl have been run-"at an ou-tpiit higher than the Maximo diese .generator ratinq. To coerect this error, the licensee agreed to re'vise..the procedure-to reflect lower current ratings based on a 0.9 power factor, sto as tQ assure the die.sel generators were operated within their continuous and 7-day ratings.

.10 FR-Part 5,Appevnd iY E, ZCrite'rfor,.'I I I, Doeign Control,. requirts measures to bees.tablished to eilsure tht deslgnb.asis.is correctly translated into specifi-c'tion- drawigs, pricedures, and instructiorS.

I($REV4NCE:

1. Electrical Restoration Remote Shutdown Procedure, Document Number
  • 3$-0PS- 2-2S,' Revision 0, Dated Jaouary 12., 1991.

UNRESOLVED ITEM 91-202-05 FINVINC TITLE: Siling of-2S0. .Vdc/600-Vc Inverter& (.Secttor 2.4 uf report)

DESCRIPTIO1 OF CONDITTION:

The- teami-revitwed the capacity of the 60.-volIt iniverter R44-S002 . providing power to four MOVs in lDivision 1, and Inverter R44-S003, providing power to fiv* MOVs in Division 2. During an accident each inverter load included operation of the RHR injection, minimunt flow, and recirculat~ing pump suction valves. Under postulated wurst-case conditions each inverter would be required to supply power simultaneously to close the recirculating discourage valve B31-FO31A and the RHR minimumi flow valve El.14FO7A.. and to stroke the RHR irjection valvt E1.1-FO14A. The team was concerned that the inverturs -may not have 'adequate capacity to provide enough power to stroke the valvt.s within tht

.time requtrcd by the technical specifications.

The lnverters were load tested every 18 months to verify their capabil.ity to stroke the r tqu~reo NGVs., Procedure 345V-R44-O01-1S "LPC; Iriverters Load Teitifng required inv'er-tvr R44-5003 10u simu~taousl stro6ke four' valvet ariýd inverter A44-SO02 to Simultaneously stroke three valves. However, the test procedure did riot measure the strokt *ime of the valves to ensure that the stroke time was within, the requirenaents of the techrical. specifications.

The licursee agreed to perform ar appropriate LPCI inverter load test during the next refueling outage to verify stroke't-i,.

Cri*terion. I.11 of 10 Cfr Part 50,. Appendix E., st."t#s that- design control measures shall prmiidt for verifying the adequacy0of design. such bs by the ptrfoemance of design. reviews, by the use of alternateor"simplifJed..calculational methods, or.*t the performance of a suitable testing program.

REFERE CE:

1. LPCI !rmv:rters Load Testing Procedure. 34SV-P44-O01,1S.

ICI *IEcY 91-240246 FINDING 'TITLE: Incorrect Coordisrtion of the EDG Circuft-Breakers (Section 2.5.1 of report)

DESCRIPTiON OF CONDITION:

The fault current relay protection on the five EDG output circuit breakers were not coordinated with the relays on the downstream breakers. For example voltage restraint overcurrent rel ay IJCV51 was incorrectly coordinated with the emergency 416G-Vult bus bratich feeder circuit breaker protective relay CO-5.

During a loss of offsite power with the COG Supplying power to the emergency 4160-volt bus, postulated faults, such as a high-impedance fault on a branch feeder, a sluggish motor start with an extended current draw near lucked rotor current, or a continuous lockied rutor condition, could cause loss of the associ-ated 4160-volt bus. The licer.see analyzed this conditfon, determined new settings for the IJCV51 relays on theL EDG output breakers, and reset these relays duilng the insptctivn.

".Tbe lfcensee did rOt recognize the EDG circuit breaker eoordination error when -

reviewing the."Plant HatchrRelaying Data Uocunmenit" during the Appemdix R fire protectior; study.

REQUIREMENTS:

ýCriteriun III of 10 CFR Part 60, Appenrdix B, states that dtsign.control measures

.,shall priuvide for.verifying the adequacy of design, such a-s by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performanct-of a suitable testing program.

REF ERENCES".

1. "Plant Hatch. Relayring. Data .Document" (also referred to as "Units I and 2 Appendix R Protective Device Coordination Study .- Off-site Source to Largest 600V"Luods"); transmitted under cover letter dated September !3, 1985.
2. Diesel- GerieratorOynaihic Loading C.dlculation 552347 (Colt/Fairbanks FMorse Engineering Report MSS99511148901R, dated hovember 14, 1989).

A-7

DEFICIENCY 91-202-07

'FINDING TITLE: Coordination Of 1'20-.Vcand 12-Vdc Circuits (Section 2.5.2 of report)

DESCRIPTION OF CONDITION:

The team roted various deficiencies in the courdination calculatiuns. Generic

-fuse coordination studies specified approved configurations for various design

.Lunditions.

Calculatiun Number 87 Elect (Bechtel), Revision 3, dated January 8, 1990 had several incorrect coordinations for specific ranges of fault current between upstream, breakers -arid downstream fuses for 120 Vdc arid 125 Vdc control circuits.

Time current curve sheet DB1, Revision 1 showed that upstream breaker Gould E41 20A had been incorrectly coordinated with Bussmnai fuse Fil4 ISA for a fault current range of over 40 amperes. The calculation showed incorrect coordination on time current curve sheets D82 for a 1fault of approximately 400 anfperes, D83 for a fault over 400 amperes, D85 for a fault ever 400 amperes, and D90 for 'a fault of 600 amperes.

The team roted that this calculation was used. in the fuse upgrade and replace-ment program, and concluded that these "approved breaker/fuse configuratlcns'l m*y have resulted in incorrect coordinotion. Approximately 6000 fuses includ-ing a1lcontrol room fuses, .had already, been reviewed i.n this program for 120 -Vac arid 12M-Vdc circulits in Units 1 and. 2. Although the-. licensee was of the opinion. that. the suspect combinations had never -had been uscd the. licrrs.ee

.greed to review the generic fuse doordin~twri stodies. and installations for incorrect coordination of breaker/fuse configuratidonsý.

.REQUIREM4ENLT -.

10 CFR Part 50, Appendix B. Criterion 111, Design Control, requires design contrul nPeasures to be provided for verifying the adequacy of design by per-forming design reviews, using, alternate or..Simplified calculational methods, or providing a suitabTe testing prugram.

REFE*RENCE:

1. Calculation titled, "Breaker/Fuse, Fuse/Fuse.Coordinatiun and Cable Auto-lgtioiun Curves for Fuse/Cable Combination for 120Vac Ind l25Vdc system," CaIcuh*tion.Number 87 Elect (Bechtel), Revision 3, dated' January 8,.1990.

A4B

OBSERVATION 91-202-08

.T41.DING TITLE: Discrepancies filCoordination Calculations (Sectioni 2.5.3 of report)

DESCRIPTION OF CONDITION:

VUrious discrepancies were noted in coordination calculations f6r the EOS

  • equipnient making it very difficult for the team to determine if the protection on the feeder breakers to essential buses was coordinated with the protection or, downstream breakers. This was because the coordination study was fragmented.

For example,. calculations SEN-89-010 and SEII-89-008 for specific overcurrent trip device modifications had nut been integrated With other calculations.

.Also, Appendix R calculations only addressed Appendix P.buses, and loads and were not integrated with other calculations. The team Concluded that this approach of satisfyIng coordination for a -specific modification could cause inadvertent errors in coordination.

There were instances of missing design input, guidelines, references, and 4ssumtpij.4.-. - Far..exampole- -results froam . short -ciruitcalculation had been .

used without the calculatiton being identified and various curves and calcula-tion sheets were not indexed, Making it difficult to determine if any sheets were mi.ssing. In addition, although.a design guideline of Z,400 amperes had been establisthed as the maximun, settirg on 600-volt instantaneous or short time t'rip devices, this guideline was not addressed in calculations, Protetiv e device .tine curet ,typicaI... curves .were used for 'mul tiple applica-tiois . However,. specific relays using-the sane typical Curve did not always have the .same -chara cter'i st ics.

The title of calcu-lation number 850841)P had been changed to "Aux Sys Coordina-titon Study4 ' from 'Statior, Aux System Short CircuitCalculation for Relaying and Fuse Co-orination Study'. . However, no changes had been. made to the b6dy of the.

calculatiorvto transform it to a coordination Study.

A-9

OEFICJEHCY 91i202-0.9

ýFMIDIRG TITLE; tDiscrepanicites in'Mechanical Designi Documevitation (Sectiln 3.1.2 of repurt)ý There weriv discrepancies iti the plant mechankial de~ign documentation.

Oi~ctpdncies wvre fuund between Colt Manual, SX 1314?, the FSAR, and associattd PSIC drawi~riis wtth regdrd to the ED6 air stort1ing compressor 4etpoirnts, ahd iperatlng porameters e~g., low pre~sure stdrto high presture cutriff, operating pressure aoii. the air recviver pressure relief Valve settjitog The seismic quialifictun. documeotation -uf selected cwtporifltes ano equtfpnent in the diesel generator Suipport s~stems showed suhe discrepancies with regard to weld' lenths toi expansion tank support brackeits and diffensions. of supports.,

There were discrepancies betwemi; the 1lcensee's calculatluns for the IfVAC systetr air flow distributicon, The air CompresSor had been replaced, ,resulting~

in. an overall lower Air teperature for tte b4ttery rcooms. However, -The rlcuatito-;is ha4 riat been revliq. to Show this- lower heat luad.

Tht urigindI lead antimony batttries had been repldred with lead calciuri Latteries thiat had a lOwkr hydrogen generator rate (xIO) than the ortgrinal botteritL. However, the hydrogen generation rates in the calculattons had not beeri revised 't reflect tht additional margins or time it would take to reacwh dangerous or explosive Conditiour,s on loss-vcf air flow tu the. battery rooms.

The P&4ariioal changes .fr Ithe Hatch Ulit 2 modification madcf under O3C-89-356 vere shown cl the plaji arrang:ement draw*igs but had not be~n. intolrpo.oratd -into the P&ID and process f luw drawings.

10 CFA Part 50, Apperidix E. Crlttrion t11. Design Control, requires measures to be established to ensure the desigr basis is-correctly translated Into specifi.

cation, drawings, proiu~1ures, and. instructiur,.

A-1O

DEFRItEKY 914r-10~l

)tL.,1f TITLE- P1.afft Serii 1CO Oter.SyritM sIPnl U plt survice water (PSV) PIP.*%~ bNtwen t~he su pply and return~

Th,0 4!1*et1w v I~ves of the1i Xehergehc.. ifesul geiw~4t had a poteti t traP s;erV1cV w~ter betwretrt~h~e standby ;u dischm~e-check vov1e 2P414r321 and the dtesw1 ~enerator cou.ling wdter ou~et valve 1Ml'F414t.

U VA&bet heat ezihangel WAS shut down,* thk covoling fluid would be tsulated by v460 o both~ sldtisv the trappte. ceWaln fluid woud@ heat up and ~txpand, and the it~t~rol pressure would ribt, thus, ipcreaslflg Mk possibility of a ow.~

Pressure C"sItioi.

_Owetpressuarizatlon of thot seCtion 0f the piping had 'the pOterItal to lrmpatr both, Lmop beCause MG~ 1B was shomred and could sopply either Uftit I-essentital bus 'IFo. Unfit e eratial.lbus 2F. The license'& cousdtted to eirnductifig a 42

  • t4684IV# O.0-a"4 ftV1ifta. d a0 approipriate -stat~icm*opteritq -pr cedlure.

This reveisior' will -require tim operators t~o maintain standby service 'water flow for , m1'owu of 112" houir aftetr the COJG was. secure* in. order to el-iminate overpressufe C~fl~re1S.

.M. CFO'Part 60, Appwndiy 9, trltertribj III-, D'es'iq Contfocl, requirits Mieasures to be estaublished to~ OBUIO,~ the design basis. fS Gurvrctlytran$ la ted. 'into Wpecff-cat Wt~f Iraw.ins, 'r.dueand-insttrtiuvs..

REFEfikCES A-Il

APPENDIX B

  • PERSCNS CONTACTED Southern Nuclear Company (SNCi/Geoiggia Power Comlpany Persotinel

'Altieer, J. N. - Project Engineer, SNC Altizer, N. - Project Engineer, SNC

'Anderson, T. - Engineering Group Manager, Electrical, SHC Barker, G. Superintendent, J&C Sennett, J. 0. - Manager, Tralnling and EP

  • Branum, J. Project Engineer, SNC Breitenbdch, K. W. - Manager, Erngineering
  • Brinstr, Jr., L. - Engineerinu, Supervisor Clair, C. - Settior Engineer. SNC Curtis, S.-. Superintendenrt Operations SuppOrt.
  • Davis, J. D. - Plant Administratiun Manager
  • Davis, R, L. - Acting SAER Site Supervfsor,.SNC.

.*Dougherty, ii. M. - Site Representative Edge, D. L. - Manager, Nuclear Sectign Frissr, 0. M. - SAEk Site Supervisor, SNC

  • Furnel, P. E. Manager, Maintenathce
  • Lewis J. - Manager, Operations

-'Garner, W. F. - Hatch Project Pranager, SNC Godby, R. K.I: Superintendent, Maintenance

.*Goode, G..A - Assistart General M6rfager Googe, M. - 'Manager, Outages and PFar4dnifig.

  • haninonds, J.- - Supervitor, Regulatory Coanplirarce

.*Heidt, J. 0. - Manager Engineer and L-icensing, 5NCo

.Madison, 0. Engineering Vanager, SNC McGaha, ... - Design Manager, Hatch

,Robertsoh, Jr., J. W. - Acting Manager, Engineering Support Rogers, W., H.- Superintendent, Chemistry Solder, B. - Supervisor, Hatch Support,. SCS.

  • Tipps, S.'- Manager, Nuclear Safety and Complidnce Vora, A. - Engineer, Maintenance Wells, P.., Superintendent Persons. Invited by the Licensee:
  • Dismukes. 1I1,O.E. - Mechanical Er.9gneerw Supervisor, Bechtel
  • Rowe, L,. . Assistanrt Project Mdnager,.Bechtel

'iWitt ,U.,o- Division Manager, CYGNA "NucearReguutoy Comni*s~iqn PersonneT

'*Fillion, P. - Reactor Inspector, R11

.*'Gautam, Imbro, E.A,V. S.- Chief, Special NRR Team Leader, Inspection Branch, NRC/NRR

  • Leung, H. - Consultant
  • Lyles, P. - Consultan:t b-1

M~a99io 'L.- 4 Consulitant-

  • Merrschoff., E. W.. -Deputyr Director,, Rvac~tvi Projects, RTI.

ErNorkfn, 0. P. - Secti~ri MO.ef PRIS, NRR

.:Sanders, S-R~eictor Cngfne'tr, NRP

.*Tran, L. NI. *Reai~tor Engineer, NRR

  • benott~s those attcwroing the ex-it irltervit.ý* on July icj, 1911 dt the~ CIThChJsiful of the inspection.
  • I0% UNITED STATES 0* NUCLEAR REGULATORY COMMISSION REGION II 101 MARIETTA STREET, NA.

ATLANTA, GEORGIA 3023 October 7. 1991 Docket Nos. 50-321, 50-366 License Nos. DPR-57, NPF-5 OCT 14 199, Georgia Power Company ATTN: Mr. W. G. Hairston, III Senior Vice President -

Nuclear Operations P. 0. Box 1295 Birmingham, AL 35201 Gentlemen:

SUBJECT:

NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-321/91-202 AND 50-366/91-202)

This refers to the inspection conducted by A. S. Gautam of this office on June 10 - July 12, 1991. The inspection included a review of activities authorized for your Hatch facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the report.

The report documenting this inspection was sent to you by letter dated August 22, 1991, Areas examined during the inspection are identifled in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice). We are concerned about the violation because of the examples of failure to establish appropriate design control measures.

You are required to respond to this letter and should follow the instructions specified In the enclosed Notice when preparing your response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NAC enforcement action is necessary to ensure compliance with NRC regulatory requirements.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be placed in the NRC Public Document Room.

Georgia Power Company 2 October 7, 1991 The responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511.

Should you have any questions concerning this letter, please contact us.

Sincerely,

- T7 Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety

Enclosure:

Notice of Violation cc w/encl:

R. P. McDonald, Executive Vice President, Nuclear Operations Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 J. T. Beckham Vice President, Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 H. L. Sumner General Manager, Plant Hatch Route 1, Box 439 Baxley, GA 31513 S. J. Bethay Manager Licensing - Hatch Georgia Power Company P. 0. Box 1295 Birmingham, AL 35201 Ernest L. Blake, Esquire Shaw, Pittman, Potts and Trowbrldge 2300 N Street, NW Washington, D. C. 20037 (cc w/encl cont'd - see page 3)

Georgia Power Company 3 October 7, 1991 (cc w/encl cont'd)

Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW Atlanta, GA 30334 Joe D. Tanner, Commissioner Department of Natural Resources 205 Butler Street, SE, Suite 1252 Atlanta, GA 30334 Thomas Hill, Manager Radioactive Materials Program Department of Natural Resources 878 Peachtree St., NE., Room 600 Atlanta, GA 30309 Chairman Appling County Commissioners County Courthouse Baxley, GA 31513 Dan Smith Program Director of Power Production Oglethorpe Power Corporation 100 Crescent Centre Tucker, GA 30085 Charles A. Patrizia, Esq.

Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW Washington, D. C. 20036

ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company Docket Nos. 50-321, 50-366 Hatch License Nos. DPR-57, NPF-5 During an NRC inspection conducted on June 10 - July 12, 1991, a violation of NRC requirements was identified. In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1991), the violation is listed below:

10 CFR Part 50, Appendix B, Criterion II1, requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, the following deficiencies were identified:

A b'~-.9 a. Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient vv l 1 voltage to perform their safety function (91-202-01).

S.... **.& b. A design review had not been performed to evaluate the impact of

' -a--1-Y load additions and transformer tap changes on the undervoltage e0 A.,.o~r. protection for the electrical distribution system (91-202-02).

c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
d. For 120-Vac and 125-Vdc circuits, coordination calculations included A% C.. 9I several approved breaker/fuse configurations which may have resulted iA#t in incorrect coordination between upstream breakers and downstream fuses (91-202-07).

This is a Severity Level IV violation (Supplement 1).

Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector, Hatch within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of Violation" and should include (for each violation]:

(1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the

Georgia Power Company 2 Docket Nos. 50-321, 50-366 Hatch License Nos. DPR-57, NPF-5 results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date wthen full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.

FOR THE NUCLEAR REGULATORY COMMISSION Caudle A. Julian, Chief Engineering Branch Division of Reactor Safety Dated at Atlanta, Georgia this 7th day of October 1991

I Georgia Power Company 40 Inverness Center Parkway r.'st Office Box 1295 1 Jrmihji am, Alabama 35201 Telephone 205 877-7279 4

J. T. Beckham, Ji. Georgia Power Vice President-Nuclear the southern elecirc system Hatch Project HL-1885 002371 November 6, 1991 U.S. Nuclear Regulatory Commni ssIon ATTN: Document Control Desk Washington, D.C. 20555 PLANT HATCH - UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION Gentlemen:

In response to your letter of October 7, 1991 and in accordance with the provisions of 10 CFR 2.201, Georgia Power Company (GPC) is providing the enclosed response to the Notice of Violation associated with NRC Inspection Report 91-202. A copy of this response is being provided to NRC Region II for review. In the enclosure, a transcription of the NRC viulatlon precedes GPC's response.

Should you have any questions, please contact this office.

Sincerely, JKB/cr 3J.TBeckham,Jr

Enclosure:

Response to Notice of Violation cc: (See next page.)

Georgia Power It U.S. Nuclear Regulatory Commission November 6, 1991 Page Two cc: Georcta Power Company Mr. H. L. Sumner, General Manager - Nuclear Plant NORMS U.S. Nuclear Regulatorv Commission. WIshington. DC.

Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Regulatory Comm-ission. Regon I I Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch 002371 700775

ENCLOSURE PLANT HATCH - UNITS 1, 2 NRC DOCKETS 50-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Violation 91-202 10 CFR Part 50, Appendix B, Criterion III, requires that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program.

Contrary to the above, the following deficiencies were identified:

a. Undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would get sufficient voltage to perform their safety function (91-202-01).
b. A design review had not been performed to evaluate the impact of load additions and transformer tap changes on the undervoltage protection for the electrical distribution system (91-202-02).
c. Fault current relay protection on the five emergency diesel generator output circuit breakers was incorrectly coordinated with the fault current relay protection on the downstream breakers (91-202-06).
d. For 120-Vac and 125-Vdc circuits, coordination calculations included several approved breaker/fuse configurations which may have resulted in incorrect coordination between upstream breakers and downstream fuses (91-202-07).

This is a Severity Level IV violation (Supplement 1).

RESPONSE TO VIOLATION Admission or Denial of the Violation GPC agrees that items b, c, and d stated above are valid deficiencies and occurred as described in the Notice of Violation. However, we believe item a does not constitute a violation. The rationale for our conclusion is provided in the response.

We emphasize that design control measures consistent with the requirements of 10 CFR Part 50, Appendix B, Criterion III are in place to provide for verifying or checking the adequacy of design. As noted in the Inspection Report, the NRC inspection team reviewed the procedures, processes, and 002450 HL-1885 El

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 guidelines governing design control measures, plant modifications, and design calculations. The inspection team concluded the following:

1. The design evaluation review and approval processes are adequate and comprehensive.
2. The engineering design and modification control processes are well proceduralized.
3. Design changes were reviewed and approved in accordance with established quality assurance/quality control controls.
4. GPC's procedures controlling documentation records and modification work are generally complete and comprehensive.

Additionally, the NRC Inspection team indicated that Plant Hatch provides a very aggressive self-assessment effort.

The four deficiencies listed as examples in the Notice of Violation are discussed below:

EXAMPLE a:

Example a is not considered a violation of NRC requirements.

The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter (GL) dated June 2, 1977 concerning staff positions for degraded grid protection of station electric distribution system voltages. The GL addressed compliance with General Design Criterion 17. In GPC's response, a range for nominal offsite line voltages, which were evaluated and shown to adequately supply the emergency loads, was established. Currently, the expected voltage range for the offsite supply is evaluated on an annual basis to include transmission system load and configuration changes since the previous study. As part of the periodic offsite source voltage study, calculations based on maximum and minimum plant and system load conditions are performed to assure acceptable voltages for emergency systems. Also, load additions to the essential buses are evaluated prior to installation under the Design Change Request (DCR) process.

GPC's methodology of using minimum and maximum acceptable voltage ranges for the offsite power supply was reviewed and approved by the NRC.

Specifically, GPC's system voltage study submitted to the NRC on October 9, 1980 used the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels. At that time, a minimum expected offsite source operating voltage of 98 percent of 230 kV was 002450 HL-1885 E2

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 identified and established to ensure adequate bus voltages. To accommodate higher expected transmission system operating voltages, tap changes were made for the Station Auxiliary Transformers in 1986 and 1987. The present minimum expected offsite source operating voltage is 101.3 percent of 230 kV. Using the present minimum expected source voltage, tap connections, and load configurations, the minimum expected 1E system voltages are, generally, slightly higher than the minimum voltages submitted in 1980. Consequently, the level of undervoltage protection determined to be sufficient in 1980 has been maintained.

The existing degraded grid undervoltage relay setpoints were approved by the NRC in the Safety Evaluation Report (SER) dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection. GPC has consistently maintained compliance with the regulatory requirements as established and approved. However, GPC and the NRC staff are presently negotiating to identify a mutually acceptable method of further improving the level of degraded grid protection at Plant Hatch.

EXAMPLE b:

Example b is considered a violation and occurred as described in the Notice of Violation.

Reason for the Violation The violation was caused by the lack of a design document specifying 1E transformer tap settings. As a result, transformer tap changes were implemented using Maintenance Work Orders (MWOs) instead of the DCR process. Consequently, formal 10 CFR 50.59 safety evaluations were not performed. Plant personnel and architect/engineer personnel failed to realize the tap changes represented design changes.

The transformer tap changes were implemented consistent with GPC's methodology of establishing minimum and maximum ranges for offsite voltages. Although formal 10 CFR 50.59 safety evaluations were not performed, engineering studies and calculations were performed to evaluate the voltage impact of plant load additions and safety-related transformer tap changes. The current transformer tap settings were changed in accordance with the recommendations resulting from the 1986 degraded grid voltage study. Currently, this study is performed on an annual basis. The study is performed in accordance with the requirements of the NRC Generic Letter of August 8, 1979 entitled, "Adequacy of Station Electric Distribution System Voltages."

002450 HL-1885 E3

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Corrective Steps Which Have Been Taken and the Results Achieved In 1990 GPC identified the need to perform safety-related transformer tap changes as part of the DCR process. Consequently, on 2/21/91, drawings were issued to control changes to power transformer tap settings in accordance with the DCR process, thereby requiring the performance of formal 10 CFR 50.59 safety evaluations.

Corrective Steps Which Will Be Taken to Avoid Further Violations Specific information for approximately 20 Class IE low-voltage transformers has not been included in the new drawings. The necessary research and plant walkdowns will be performed to verify the remaining IE transformer tap settings. Transformer inspections which do not require deenergization will be complete by 3/31/92. Examinations of transformers that require deenergization will be complete by the end of the next refueling outage for each unit. Drawings will be updated as necessary.

Date When Refueling Full Compliance Will Be Achieved Full compliance for accessible transformer will be achieved by 3/31/92 when drawings will be issued. The remaining transformers will be included on the drawings by the next refueling outage. This will require the performance of 10 CFR 50.59 safety evaluations for future transformer tap changes.

EXAMPLE c:

Example c is considered a violation and occurred as described in the Notice of Violation.

Reason for the Violation The violation was caused by personnel error. GPC protection engineering personnel did not sufficiently evaluate the coordination of the EDG overcurrent protection relays with the protective relays for the downstream circuit breakers. Additionally, GPC protection engineering personnel failed to identify the incorrect coordination during their review of the Appendix R Fire Protection Study which was performed in 1985. GPC personnel did not sufficiently evaluate the coordination scheme to ensure the required coordination was achieved.

As discussed during the inspection, the overcurrent relay protection on the five emergency diesel generator (EDG) output circuit breakers was functionally coordinated with the relay protection on the downstream 002450 HL-1885 E4

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 breakers, with the exception of postulated faults such as a high impedance fault, a sluggish motor start with extended current draw near locked rotor current, or a continuous locked rotor condition on the associated 4160-V pump motors. These type scenarios are evaluated under single-failure analyses.

The single-failure criterion applicable to this issue is based on ANSI/ANS 52.1, "Nuclear Safety Criteria for the Design of Stationary Boiling Water Reactor Plants." Section 3.2.1 states:

The single failure criterion requires that the plant be capable of achieving (1) emergency core reactivity, control, (2) emergency core and containment heat removal and (3) containment isolation, integrity, and atmospheric cleanup given an initiating occurrence plus an independent single failure of a nuclear safety related component in any one of the systems required to support directly or indirectly these three nuclear safety functions (i.e. only one single failure need to be assumed in the plant nuclear safety related equipment for any initiating occurrence).

ANSI/ANS 52.1 Is related to the specific question as follows:

For a given initiating occurrence, GPC is required to ensure no single equipment failure will prevent adequate core cooling or adversely affect containment integrity. The failure is not specifically stated; therefore, the failure of any single piece of equipment must be considered credible.

For Plant Hatch, one of the limiting single failures is the total loss of an EDG. The hypothetical loss of an EDG can be from any cause. An EDG failure may be initiated by several different sources; for example, from a start signal failure or a fault on the load side of a 4-kV breaker, or other component failures.

The loss of an EDG is an analyzed event. All Appendix K requirements are satisfied, and containment integrity is not violated. The key Issue for single failure is that it may occur prior to, during (simultaneously), or subsequent to the initiating (accident) event. The scenario must be analyzed for the most severe chronological occurrence of events so the plant successfully achieves mitigation of the accident.

While the loss of an EDG due to less than fully adequate breaker coordination is an undesirable event, GPC maintains that such a scenario is within the licensing basis of the plant.

002450 HL-1885 E5

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPQRT 50-321191-202: 50-366/91-202 Corrective SteDs Which Have Been Taken and the Results Achieved Design Change Requests91-124 and 91-125 were implemented on 7/12/91 to revise the settings on the diesel generator output breakers to correctly coordinate the protective devices.

Corrective Steps Which Will Be Taken to Avoid Further Violations No further corrective actions are required.

Date When Full Compliance Will Be Achieved Full compliance was achieved on 7/12/91 when DCRs91-124 and 91-125 were implemented.

EXAMPLE d:

Example d is considered a violation and occurred as described in the Notice of Violation.

Reason for the Violation The violation was caused by personnel error. Electrical calculation No. 87 (Bechtel), Revision 3, dated January 8, 1990, identifies various acceptable configurations between existing upstream circuit breakers and downstream fuses for 120-Vac and 125-Vdc control circuits. Although no use of this calculation to select new fuse/breaker combinations is believed to exist, the intended us of the coordination tables was not adequately defined, and could have been misinterpreted. This calculation is not a basis for selecting fuse/breaker combinations in circuits where coordination is mandatory (i.e., Appendix R).

Corrective SteDs Which Have Been Taken and the Results Achieved Electrical calculation No. 87 has been revised to clearly state its scope and purpose. The revision ensures that further reviews, if required, will be performed when undertaking coordination studies using this calculation.

Additionally, a review was performed during the inspection and it is believed that the area of concern (overlapping of trip curves at relatively high fault levels) does not apply to any actual plant circuits.

002450 HL-1885 E6

ENCLOSURE (Continued)

RESPONSE TO NOTICE OF VIOLATION NRC INSPECTION REPORT 50-321/91-202: 50-366/91-202 Corrective SteDs Which Will Be Taken to Avoid Further Violations A review of the calculation will be performed to ensure it did not result in misapplications which cause an inappropriate level of coordination.

This action will be complete by 3/31/92. Appropriate A/E personnel have been. counseled regarding the need for correctly translating design information.

Date When Full Compliance Will Be Achieved Full compliance was achieved on 10/30/91 when Electrical Calculation No. 87 was revised to more clearly state its scope and purpose.

002450 HL-1885 E7

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 I. INTRODUCTION S. J. BETHAY II. BACKGROUND AND S. J. BETHAY CURRENT STATUS III. OFFSITE POWER SYSTEM M. B. MILLER IV. OPTIONS CONSIDERED T. 0. ANDERSON V.

SUMMARY

J. D. LIEIDT VI. OPEN DISCUSSION

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992

SUMMARY

I. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.

II. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS.

  • RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM
  • SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES
  • 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS (<101.3%)
  • AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT
  • ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT
  • FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ISSUE SUMIMARY I. DURING SUSTAINED DEGRADED GRID CONDITIONS AT OR SLIGHTLY ABOVE THE CURRENT SETPOINT, THE UNDERVOLTAGE PROTECTION WAS NOT CONSIDERED ADEQUATE TO ENSURE SAFETY-RELATED EQUIPMENT AT 600 VOLTS AND BELOW WOULD BE SUPPLIED WITH ADEQUATE VOLTAGE.

  • LOCA ACCIDENT CONDITIONS CONCURRENT WITH A DEGRADED GRID.

HYPOTHETICAL ALARM / TRIP RANGES MIN EXPECTED VOLTAGE ALARM SETPOINT TRIP SETP OINT MIN REQUIRED VOLTAGE

4.1I6KV 290KV 104.9 96.7 EXP 103.5 101.9 92 ALARM 91 .4 REG 91.14 EXP 90.8 REG DEADBAND 88.94

I TRIP GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES I. ENSURE THE PLANT IS ADEQUATELY PROTECTED FROM UNDERVOLTAGE CONDITIONS.

" ASSESS THE LEVEL OF SAFETY PROVIDED BY THE CURRENT SYSTEM

" IDENTIFY AVAILABLE OPTIONS

" DETERMINE IF IMPROVEMENTS ARE FEASIBLE II. ENSURE OFFSITE POWER IS PRESERVED AS THE PREFERRED SOURCE.

III. DEVELOP AN INTEGRATED APPROACH CONSIDERING THE ELECTRICAL DESIGN REQUIREMENTS, SYSTEM OPERATION AND PLANT OPERATION.

IV. AN UNDERVOLTAGE RELAY SETPOINT WITHIN THE NORMAL SYSTEM OPERATING RANGE IS UNACCEPTABLE.

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 GPC OBJECTIVES (CONTINUED)

V. AN ORDERLY, FAST REACTOR SHUTDOWN IS PREFERABLE TO AN AUTOMATIC ISOLATION OR SELF INDUCED REACTOR ISOLATION TRANSIENT WITHOUT OFFSITE POWER.

  • SYSTEM OPERATORS SHOULD BE ALLOWED TO QUICKLY MITIGATE A DEGRADED GRID TRANSIENT TO AVOID AN UNNECESSARY ISOLATION TRANSIENT AND A FURTHER CHALLENGE TO GRID STABILITY.
  • SYSTEM OPERATIONS SHOULD ASSESS THE CHALLENGE TO THE GRID AND DETERMINE IF QUALITY OFFSITE POWER CAN BE MAINTAINED.

VI. ENSURE RESOLUTION DOES NOT RESULT IN AN ACTUAL DECREASE IN OVERALL SAFETY.

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CRITERIA

1. RISKS ASSOCIATED WITH AN AUTOMATIC SHUTDOWN MUST BE BALANCED WITH THE RISKS ASSOCIATED WITH CONTINUED OPERATION.

II. RISKS ARE ASSIGNED AS A FUNCTION OF:

  • THE RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM'S GRID VS. RELIABILITY OF ONSITE POWER
  • THE SOUTHERN ELECTRIC SYSTEM'S GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES VS. SETPOINT CONTROLS
  • THE EXTREMELY LOW PROBABILITY OF DEGRADED VOLTAGE AT PLANT HATCH VS. THE POSSIBILITY OF SPURIOUS REACTOR ISOLATION TRANSIENTS ON THE PLANT
  • THE PROBABILITY OF OFFSITE VOLTAGE FALLING BELOW 101.3% IS 4.3X10- 8
  • THE ANTICIPATED DURATION OF A DEGRADED GRID CONDITION
  • THE POTENTIAL EFFECT OF BRIEF DEGRADED VOLTAGE ON PLANT EQUIPMENT VS. THE EFFECT FROM AN ISOLATION TRANSIENT WITH 3 BUSSES AVAILABLE ON ONE UNIT AND 2 BUSSES ON THE OTHER
  • THE SYSTEM IMPACT OF SEPARATING 1600MW FROM A DEGRADED GRID

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 ACTIONS COMPLETED I. HARDWARE AND SETPOINT CHANGES HAVE BEEN INVESTIGATED.

1I. WORKED WITH SYSTEM OPERATIONS TO GAIN AN UNDERSTANDING OF:

" THE GRID MONITORING AND SINGLE FAILURE ANALYSIS CAPABILITIES

" SYSTEM OPERATING PROCEDURES THAT ENSURE ADEQUATE VOLTAGE IS MAINTAINED

" THE SYSTEM CONDITIONS WHICH WOULD HAVE TO OCCUR TO PRODUCE DEGRADED VOLTAGE AT PLANT HATCH III, INSTALL ANTICIPATORY ALARMS.

IV. FORMALIZED ANTICIPATORY ACTION - BOTH ONSITE AND OFFSITE.

V. FORMALIZED COMMUNICATIONS WITH SYSTEM OPERATIONS.

V-I IMPLEMENTED AN OPERATING ORDER TO ENSURE THE REACTOR IS QUICKLY BROUGHT TO A CONDITION OF GREATER SAFETY.

  • PROVIDES ACTIONS CONSISTENT WITH TECHNICAL SPECIFICATIONS ACTIONS FOR FAILURE OF ALL DIESEL GENERATORS

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SOUTHERN ELECTRIC SYSTEM (SES) SECURITY S"OPERATION CENTERS

  • ON LINE COMPUTERIZED LIBRARY OF REGIONAL AND SUBSTATION SINGLE LINES

-..O CONTINUOUS MONITORING AND CONTINGENCY ANALYSIS

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GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 IF 230KV SYSTEM FAILS BELOW 101.3%

  • RECEIVE LOW VOLTAGE ALARM a NOTIFY CONTROL ROOM AT PLANT HATCH
  • PUT CAPACITOR BANKS ON
  • TURN SHUNT REACTORS OFF 0 PUT COMBUSTION TURBINES (McMANUS) IN SERVICE
  • BRING OUT OF SERVICE ELEMENTS BACK TO SERVICE a REDUCE LOAD

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992 CONCEPTUAL MODIFICATIONS APPROXIMATE COST I. TAP CHANGES $ 250,000 II. NEW RELAYS, CABLE $ 500,000- $1 MILLION AND / OR EQUIPMENT CHANGE OUT III. NEW LOAD SHED / BUS $1 - 2 MILLION TRANSFER SCHEMES IV. RE ANALYSIS OF EXISTING $1 - 2 MILLION LOAD AT LOWER VOLTAGE V. NEW MAJOR EQUIPMENT $ 10 MILLION

290KV '1.16KV 104.9 96.7 EXP 1095 101.9 40, 92 - ALARM 91.4 REQ 91.14 EXP 90.8 REQ DEADBAND 88.94 a-- TRIP

GEORGIA POWER COMPANY PLANT E. I. HATCH DEGRADED GRID ISSUES NOVEMBER 16, 1992

SUMMARY

I. GPC REQUESTS NRC APPROVAL OF ADMINISTRATIVE IMPLEMENTATION OF BRANCH TECHNICAL POSITION PSB-1.

II. GPC'S SOLUTION INTEGRATES THE REQUIREMENTS FOR ELECTRICAL DESIGN, PLANT OPERATIONS AND SYSTEM OPERATIONS.

III. THE METHODS IN PLACE PROVIDE AN ADEQUATE LEVEL OF SAFETY, AND IN SOME SCENARIOS, A HIGHER LEVEL OF SAFETY WHEN COMPARED TO AUTOMATIC CONTROLS.

" RELIABILITY OF THE SOUTHERN ELECTRIC SYSTEM

" SOUTHERN COMPANY SYSTEM CONTROL POLICIES AND PROCEDURES

" 10-8 PROBABILITY OF DEGRADED VOLTAGE CONDITIONS

(<101.3%)

" AN ORDERLY, FAST SHUTDOWN IS PREFERABLE TO AN AUTOMATIC OR SELF INDUCED REACTOR ISOLATION TRANSIENT

" ADVERSE SYSTEM IMPACT FROM AUTOMATIC DISCONNECT IV. FURTHER ENHANCEMENTS ARE NOT COST BENEFICIAL

GeorginePowr Company 40 Inverness Center ParBkway post Ofitoe Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 J. T. Beckham, Jr. Georgia Power Vice President - Nuclear Hatch Project Ithe soC.nerl erE,.'., -

November 22, 1993 Docket Nos. 50-321 HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory Comrrm*ssion ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:

On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.

During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the. current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.

Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.

As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).

OC orgia Power U.S. Nuclear Regulatory Commission -.Page Two November 22, 1993

.Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.

Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased. In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required. Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary. Consequently, GPC does not consider further actions to be necessary.

The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.

Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.

Sincerely, T.Beckham, Jr JKB/cr 004440

Enclosure:

Degraded Grid Voltage Protection cc: (See next page.)

Georgia Power A U.S. Nuclear Regulatory Commission Page Three November 22, 1993 cc: GeorgWa Power Comvani Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear Regplaiog Commission, Washington,D.C.

MW. K. Jabbour, Licensing Project Manager - Hatch U.S. NuclearRegulatory Commission. Regiion II Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch

Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection BackUround The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC) implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided. This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.

Origin of the 1ssue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers. An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors. As a result, the control power fuses were blown when the 480 volt motors were signaled to start.

At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.

However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.

HL-4440 E-1

Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.

Additional information is contained in GPC's submittals dated September 17, 1976; January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.

GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.

EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts),

certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.

By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function. By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection. GPC concluded that a violation of NRC requirements did not exist based on the following:

HL-4440 E-3

Enclosure Degraded Grid Voltage Protection

1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.
2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained. In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected. At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.

Consequently, tap changes were made for the startup transformers in 1986 and 1987.

Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4.160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected IE system voltages are, generally, slightly higher than the bus voltages submitted in 1980.

3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible. GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would represent a marginal to safety improvement. This conclusion is based on the following:

A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone. The Southern electric system employs state-B-.4440 E-4

Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis' feature allows system operation to predict adverse affects from postulated system failures. Based on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion. Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes.

" System operators receive low voltage alarm.

  • System operators notify the control room at Plant Hatch.
  • The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off).
  • The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).
  • Capacitor banks in the surrounding area are turned on (if oft).
  • Combustion turbines at Plant McManus are placed in service.

These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:

  • Out of service elements are brought back on line.
  • System load (external or internal) is reduced.

Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.

HIL-4440 E-5

Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs),

limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management. The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored. The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-SI1-001-OS, "Operation With Degraded System Voltage."

Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.

This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.

An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.

During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440 E-6

Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.

The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.

GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.

As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.

Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion. Corrective actions have been taken to clarify this requirement and assure proper communications.

HL-4440 E-7

Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.

  • The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.
  • The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.

" The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.

" If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred. However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.

Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.

The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation. In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been increased.

C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable. This conclusion is based on the following:

HL-4440 E-8

Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required. GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.

Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available. Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection. As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications. Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.

GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint. While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440 E-9-._

Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected. Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.

Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved:

" The electrical requirements of safety-related equipment.

" The reliability of the offsite power supply.

" The potential adverse effects to the plant caused by an unnecessary disconnect from the offisite power source.

" The extremely low probability of a sustained degraded grid event concurrent with a LOCA.

  • The impact to the offisite power system caused by separating up to 1600 MW during a degraded grid event.

As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would likely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum

  • required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.

HL-4440 E-10

ATTACHMENT 1 EDWIN 1. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION

Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution System Description Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.

The GPC system is also designed to connect generating units to the grid at optimum locations. This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.

The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.

The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided in Figure 1.

Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.

The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.

The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.

The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, R.HR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.

HL-4440 A-!I

Attachment I Electrical System Description During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C.. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.

During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.

During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.

-L-4440 A-2

me Ia. In. Ifl.

M~ *~S 4-.'.'-

oooA, Z.m-m 0; Is -oak

-S

  • 1-13{50 - UNIT I MIAIN POWER DISTRIBUJTION M&IN POW"fR IISFIIJIIaI.

EDWIN I nATCH - UNII 2 EDWIN 4 IIAIC. - 4 I "4I I-I-2950 - UNIT 2 FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS - NORMAL OPERATION

ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARM/TRIP RANGES

HYPOTHETICAL ALARM / TRIP RANGES NUN EXPECTED VOLTAGE ALARM SETPOIN'T TRIP SETPOINT MEN REQUIRED VOLTAGE

ATTACHMENT 3 EDWIN 1. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS

P~ant Hatch Unit 1 Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E DEAD BAND CALC, 92764PG

P~ant Hat+/-ch Unit 1 Bus-F 4.16KV 97.6 EXP 104.9 103.5 101,3 ALARM 88.47 REQ E DEAD BAND CALC. 92764PG

Plant Ha~tch Unit 1 Bus G

,'V 97.6 EXP 104.9 103.5 (-

101.3 ALARM

.. 91.4 RE 0 9

9D SDEAD BAND CALC. 92764PG

I Ptant Haoch Unit 2 Bus- E 4.16KV 230KV 97.85 EXP 104.9 103.5 101.3 93.81 EXP ALARM 90.73 REQ 90.05 REQ 7

88.34 I i M DEAD BAND CALC, 92763PG

Georgia Power Company 40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279 A J. T. O.c.am, J,.

Vice President - Nuclear Georgia Power Hatch Project July 1, 1994 Ihe SoLthern electrfc systern Docket Nos. 50-321 HL-4586 50-366 TAC No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1.Hatch Nuclear Plant Degraded Grid Protection Gentlemen:

Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.

The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.

'orgia Power A U.S. Nuclear Regulatory Commission Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.

GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the offsite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to the initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-I of the Unit I and Unit 2 Technical Specifications, respectively.

GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband. Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement. If voltages are not restored within one hour, a plant shutdown is then initiated.

ll

.'orgiaPower A U.S. Nuclear Regulatory Commission Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into the Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications. Accordingly, the limiting condition of operation (LCO) will require the degraded grid alarms to be operable in modes 1, 2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable. Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.

Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded. GPC has evaluated this request to raise the alarm setpoints to 97 percent of4160 volts and determined that it is not feasible nor required. The basis for this conclusion is as follows:

The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required. As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.

As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.

r'*orgia PowerA U.S. Nuclear Regulatory Commission Page Four July 1, 1994 The current alarm setpoints of approximately 92 to 93 percent of 4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions. The current alarm setpoint values signify that adequate voltage is available for normal operations. Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-00 1-OS, "Operation With Degraded System Voltage" if the voltage cannot be restored. Procedure 34AB-SI 1-001-OS directs operators to initiate a "one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation. An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers. From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.

Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint. Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.

Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation. As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations. GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.

!orgia Power A U.S. Nuclear Regulatory Commission Page Five July 1, 1994 Should you have any questions in this regard, please contact this office.

Sincerely, Jr.

? J.T. Beckhani, MKB/cr cc: GeorgiaPower Compa-nv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS U.S. NuclearRegulatory Commission. Washington. D.C.

Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Reyloaoro Commission. Region I)

Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector - Hatch

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 10, 1995 LICENSEE: Georgia Power Company, et al.

FACILITY: Hatch Nuclear Plant, Units 1 and 2

SUBJECT:

SUMMARY

OF DECEMBER 7, 1994, MEETING WITH GEORGIA POWER COMPANY ON DEGRADED GRID VOLTAGE - HATCH NUCLEAR PLANT, UNITS I AND 2 (TAC NO. M80948)

On December 7, 1994, the NRC staff met with Georgia Power Company (GPC or licensee) representatives and their consultant from Southern Company Services (SCS) in Birmingham, Alabama, to discuss equipment operability under degraded grid conditions at Plant Hatch, Units 1 and 2. Attachment 1 lists the attendees and Attachment 2 contains a copy of the vlewgraphs used by the licensee during the presentation.

After brief introductory remarks by NRC and GPC regarding the objectives of the meeting, Mr. J. Branum, GPC, provided a summary of previous correspondence and meetings regarding the same subject. He stated that NRR staff's concerns originated from an electrical distribution system functional inspection completed in July 1991. He discussed the licensing basis associated with the existing setpolnt for the degraded grid undervoltage relays and GPC's concerns when raising the setpoint.

Georgia Power's concerns are based on the low probability of a sustained degraded grid event combined with a loss-of-coolant accident, the existing narrow range between the minimum expected voltage and the minimum required voltage, the possibility of introducing unnecessary trips of the offsite power supply, and the need for major plant modifications. Mr. Branum also discussed the methods for maintaining the minimum required switchyard voltage, the basis for the setpoint of the undervoltage alarm relays, plant procedures for responding to a degraded grid event, and the incorporation of the alarm setpoint into the improved Technical Specifications.

During a followup discussion, Messrs. S. Bethay, GPC, and B. Snider, SCS, provided additional details of the alarm setpoint. The setpoint is set as high as practical to provide notification of bn'undervoltage* condition during normal operation but also to avoid unnecessary alarms whirl the balance-of-plant equipment is powered from the startup transformers. Mr. Bethay also discussed the ability of the plant to respond to a postulated undervoltage condition. His statements were based on the pl-'at's responrse to a station blackout condition where the pressure systems provide inventory makeup. These systems rely on DC power rather than AC power. Georgia Power concluded the meeting by stating that the existing degraded grid-rotectlon system is adequate and that further modifications are not necessary.

The NRC staff had several comments regarding the alarm and the operator actions. In addition, the staff requested that the Final Safety Analysis Report (FSAR) be amended to provide information on GPC's approach to degraded grid protection which should include a discussion of the alarms and the operating range at the 230 KV level. GPC agreed to update the FSAR.

At the conclusion of the meeting, the NRC staff stated that they will review GPC's submittal and the handouts with the view that the approach proposed by GPC constitutes a deviation from the recommendations of the Generic Letter dated June 2, 1977.

Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366 Attachments: 1. List of Attendees

2. Viewgraphs cc w/Attachments: See next page

Georgia Power Company Edwin I. Hatch Nuclear Plant cc:. Mr. Ernie Toupin Mr. Ernest L. Blake, Jr. Manager of Nuclear Operations Shaw, Plttman, Potts and Trowbridge Oglethorpe Power Corporation 2300 N Street, NW. 2100 East Exchange Place Washington, DC 20037 Tucker, Georgia 30085-1349 Mr. S. J. Bethay Charles A. Patrizia, Esquire Manager Licensing - Hatch Paul, Hastings, Janofsky & Walker Georgia Power Company 12th Floor P. 0. Box 1295 1050 Connecticut Avenue, NW.

Birmingham, Alabama 35201 Washington, DC 20036 Mr. L. Sumner Mr. Jack 0. Woodard General Manager, Nuclear Plant Senior Vice President -

Georgia Power Company Nuclear Operations Route 1, Box 439 Georgia Power Company Baxley, Georgia 31513 P. 0. Box 1295 Birmingham, Alabama 35201 Resident Inspector U.S. Nuclear Regulatory Commission Chairman Route 1, Box 725 Appling County Commissioners Baxley, Georgia 31513 County Courthouse Baxley, Georgia 31513 Regional Administrator, Region II U.S. Nuclear Regulatory Commission Mr. J. T. Beckham, Jr.

101 Marietta Street, NW. Suite 2900 Vice President - Plant Hatch Atlanta, Georgia 30323 Georgia Power Company P. 0. Box 1295 Mr. Charles H. Badger Birmingham, Alabama 35201 Office of Planning and Budget Room 610 270 Washington Street, SW.

Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334

NRC/GPC MEETING DECEMBER 7. 1994 ORGANIZATION K. N. Jabbour NRC/NRR

0. F. Thatcher NRC/NRR/EELB N. K. Treham NRC/NRR/EELB Gary McGaha SCS-Hatch Tom Sims SCS-CATS Jeff Branum SNC/NEL Bill Snider SCS/Hatch Roger Hayes SNC/Farley David Gambrell SCS-Farley Steve E. Bethay SNC-Hatch Engineering Attachment I

Edwin I. Hatch Nuclear Plant Degraded Grid Protection December 7, 1994 Agenda Introduction J. D. Heidt Overview of Correspondence/Meetings J. K. Branum Selected Topics J. K. Branum

" Basis for existing setpoints

" Concerns with raising setpoints

" Plant procedures and technical specifications Discussion All Conclusion J.D. Heidt Attachment 2

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings

1. EDSFI performed in May/June of 1991
  • NRC team questioned whether the undervoltage relay setpoints were too low to ensure minimum voltage prior to disconnect from offsite power supply.
2. GPC Meeting with NRC on 8/6/91

" GPC discussed offsite system controls, extremely low probability of a sustained degraded grid and LOCA, and operating enhancements.

"NRC Staff indicated agreement with GPC's conclusions.

3. Inspection Report 91-202, dated 8/22/91
  • Restated EDSFI Team's concern
4. Notice of Violation, dated 10/7/91
5. GPC Reply to NOV, dated 11/6/91
  • Denied violation

" GPC determined a violation of NRC requirements did not exist

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Overview of Correspondence/Meetings (Continued)

6. GPC Meeting with NRC on 11/16/92 "GPC provided objectives and criteria used in assessment.

"Detailed discussion of offsite system monitoring and controls

  • Actions completed
  • Cost estimates for conceptual modifications
7. GPC letter, dated 11/22/93 "Basis for existing setpoints
  • Basis for concerns for unnecessary disconnects
8. GPC letter, dated 7/1/94
  • Basis for alarm setpoints
  • Committed to include alarm in improved Technical Specifications
  • Formally requested NRC review and approval

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Selected Topics

1. Basis for existing undervoltage relay setpoints
2. Concerns with raising setpoints
3. Basis for alarm setpoints
4. Plant procedures and Technical Specifications

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints

  • Existing setpoints are in accordance with GPC's response to the NRC generic letter dated June 2, 1977 "Existing setpoints were approved in the Safety Evaluation report dated 5/6/82

" GPC used maximum plant loadings to establish the minimum expected voltage for the offsite power supply to assure the adequacy of plant voltage levels

Edwin I. Hatch Nuclear Plant Degraded (rid Protection

  • A sustained degraded grid is not a credible event for Plant Hatch The Southern Electric System employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure adequate voltage is provided and the contingency analysis feature allows prediction of the adverse affects from postulated system failures.
  • System operators configure the offsite power supply such that a failure can occur without adversely affecting the minimum required voltage. This includes postulated trips of a Hatch unit.

e A dynamic voltage excursion is more likely

Ptant Hatch Unit 1 Bus G 104.9 97.6 EXP 103.5 102.6 101,3 192.96 EXP ALARM 91.4 REQ DEGRADED GRID 8034 SETPOINT O DEAD BAND CALC. 94738PG

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Existing Undervoltage Relay Setpoints (Continued)

" The occurrence of a sustained degraded grid is extremely unlikely

" The occurrence of a LOCA is estimated at 2.61 x 10.4

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Concerns With Raising Undervoltage Relay Setpoints "The existing range between the minimum expected voltage with the grid at 101.3 percent and the minimum required voltage for LOCA loads is too narrow "Raising the setpoint could result in unnecessary and unwanted disconnects within the expected voltage range.

  • Raising the setpoint could result in a trip from the offsite power supply during a LOCA when offsite power is fully adequate.

9 Increasing the narrow range would require major plant modifications

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Dynamic Excursion vs Sustained Degraded Grid The most likely degraded grid event is a dynamic voltage excursion For a dynamic voltage excursion, disconnecting both units from offsite power and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.

GPC's method of using manual actions in the deadband range allows system operators to quickly stabilize a degraded grid without introducing a plant transient when offsite power is undergoing a temporary excursion and is not in actual jeopardy.

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Conce2tual Modifications Approximate Cost

1. Transformer tap changes 250,000
2. New undervoltage relays, cable/ 500,000 - 1 million equipment replacement
3. New major equipment 10 million

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Undervoltage alarm setpoint is as high as practical Setpoint is approximately midway between the minimum voltage for operation (BOP equipment on SAT's) and the expected voltage with the grid lowered to 101.3 percent (above 92 percent)

A higher alarm setpoint of 97 percent would be expected to generate frequent false alarms when non-safety loads are powered from the startup transformers.

The alarms are also expected to annunciate during a LOCA if the grid has lowered to 101.3 percent

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Basis For Undervoltage Alarm Setpoint Alarm annunciation indicates that an undervoltage condition is present:

However, voltage is adequate for normal operation (i.e., voltage levels, equipment performance, and availability of equipment is satisfactory).

Edwin I. Hatch Nuclear Plant Degraded Grid Protection ActfiQns Completed

1. Increasing the undervoltage relay setpoint and replacing the relays have been evaluated.
2. Evaluated system operations grid monitoring and failure analysis capabilities.
3. Installed anticipatory alarms.
4. Formalized anticipatory actions both onsite and offsite.
5. Implemented annunciator response and abnormal operating procedures to ensure the reactor is quickly brought to a condition of greater safety.
6. Incorporated the alarms into the improved technical specifications.
7. Installed an additional capacitator bank in the 230 Kv switchyard to provide three levels of adjustment.

Edwin I. Hatch Nuclear Plant Degraded Grid Protection Summary The existing degraded grid protection system using manual actions in the deadband area followed by automatic controls provides adequate safety.

The existing system provides a higher level of safety when compared to automatic controls for more likely transient scenarios.

GPC has expended considerable resources to resolve NRR staff concerns.

Further actions are not necessary.

1.0 IDENTIFICATION

ALARM PANEL 652-1 4160V. BUS 1E VOLTAGE LOW DEVICE: SETPOINT:

1S32-K206-1/2 3867 volts

2.0 CONDITION

3.0 CLASSIFICATION

A low voltage condition was sensed on 4160V BUS IE. EOUIPMENT STATUS

4.0 LOCATION

l~l1-P652 PANEL 652-1 5.0 OPERATOR ACTIONS:

5.1 Confirm that voltage is less than 3867 volts on Panel 1111-P652 on 4160V BUS IE Voltmeter.

5.2 1E voltage is below 3867 volts; notify Georgia Control Center and request operator to raise the voltage on the system to normal.

5.3 If voltage on the system cannot be restored, enter 34AB-SIl-OOl-OS, Operation with Degraded System Voltage.

.6.0 CAUSES:

6.1 System voltage is low

7.0 REFERENCES

8.0 TECH. SPEC./LCO:

7.1 H-13412, Elementary Diagrams Diesel 8.1 3/4.9, Electrical Power Systems Gen IA DEPT. MGR DATE _ 34AR-652-122-IS IRev. 4 MGR-0048 Rev. I 21DC-DCX-001-OS

GEORGIA POWER COMPANY DOCUMENT TYPE: PAGE I OF 2 PLANT E.I. MATCH[ ABNORMAL OPERATING PROCEDURE TITLE. DOCUMENT NUMBER: REVISION NO:

OPERATION WITH DEGRADED SYSTEM VOLTAGE 34AB-Sll-001-os I EXPIRATION DATE: APPROVALS: MARKUP APPROVED BY: EFFECTIVE DEPARTMENT MANAGER J.C. LEWIS DATE 3-19-93 DATE:

N/A GMNP/AGM-PO/AGK- PS N/A DA*3-19-93

__ _..r-

___ -r, r*v,- ^* .r" 1.0 CONDITIONS 1 S':?,~ SUPORT SO r..-jQ11N1NT CONTROL

?V~

I Normal minmum voltage with either Unit in modem 1, 2, or 3 in 233KV. Normal minimum voltage with both units in COLD SHUTDOWN, REFUEL or with Fuel Ramved is 225KV.

1.1 The System Operating Center (Birmingham) ham notified the Superintendent On Shift that the Offmite Distribution System is in jeopardy of ZM being able to maintain normal minimum voltage at the 230KV bum.

1.2 The System Operating Center has notified the Superintendent On Shift that the 230KV Bus voltage C be maintained above normal minimum voltage.

2.0 AUTOMATIC ACTIONS None 3.0 I!4EDIATE OPERATOR ACTIONS N/A - not applicable to this procedure.

4.0 SUBSEOUENT OPERATOR ACTIONS 4.1 Upon notification from System Operating Center that the Offmite Distribution System is one contingency (event) away from being unable to maintain normal minimum voltage on the 230KV bus, the following action. are to be taken:

4 .1.1 RETURN inoperable Emergency Diesel Generators to operable status as soon an possible.

4.1.2 NO maintenance QS surveillance is to be initiated an critical comonents of the on-mite electrical distribution system AM those in process are to be RESTORED to normal an TZiIMRTED as moow am possible.

4.1.3 ASSIGN an operator to monitor the voltage indicators for the mix 4160 VAC Emergency buses (l/2R22-S005,6,7) twice per hour. U the indicated voltage is greater than 3850VAC, 3= the bus voltages are considered acceptable.

MGR-0002 Rev. 5

4.1.4 INFONI the entire shift operating crew = RSCORD appropriate log entries of the increased potential for a degraded voltage QR lose of offsite power event.

4.1.5 Notify the Manager of Operations, the On-site Duty Manager and the On-call Hatch Project Duty Manager.

4.2 Upon notification from System Operating Center that the 230KV bus voltage C be maintained above normal minimum voltage, QOZU the 4160VAC bus voltagese be maintained above 38SOVAC, the following action will be taken:

4.2.1 INMTxATh an won* Hour LCON to RZSTODR the 4160VAC Bus voltages to acceptable levels (greater than or equal to 3850VAC).

4.2.2 Notify the Manager of Operations, the On-site Duty Manager, and the On-call Hatch Project Duty Manager.

4.2.3 U the 416OVAC Bus voltages are fnO R.STORZD acceptable levels WAMN one hour, an orderly plant SHUTDOWN will be rINTIATKD with the intent of reaching HOT SHUTDOWN in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN NZ=ZN the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Refer to 73SP-SIP-001-OS and notify the NRC by the EqS (fPX 2000).

MGR-0001 Rev. 1

LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE. .-. I I

APPLICABILITY: MODES 1, 2, and 3, When the associated diesel generator (DG) is required to be OPERABLE by LCO 3.8.2. *AC Sources - Shutdown."

ACTIONS

.NT - . .*" " U.

NOTE----------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Restore channel to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable for OPERABLE status.

Functions 1 and 2.

B. One or more channels B.I Verify voltage on Once per hour inoperable for associated 4.16 kV Function 3. bus is ? 3825 V.

C. Required Action and C.1 Declare associated DG Immediately associated Completion inoperable.

Time not met.

HATCH UNIT 1 3.3-67 REVISJO C

LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)

Lose of Power Inst'iaventetion REQUIRED CNAMMELS SURVEILLANCE ALLOWUALE FUNCTION PER BUS REWIIRENENTS VALUE

1. 4.16 kV Emergency Bus Urndervoltage (LOSS of Voltage)
a. Bus Undervottage 2 So 3.3.8.1.2 t 2100 V SR 3.3.8.1.3 SA 3.3.8.1.4
b. Tim Deley 2 S8 3.3.8.1.2 S11 3.3.8.1.3 s 6.5 seconds sm 3.3.8.1.4
2. 4.16 kV Emargency Bus Undervottage (Degreded Voltage)
a. Ilu Undervoltage 2 SR 3.3.8.1.2 x 3280 V SR 3.3.8.1.3 sm 3.3.8.1.4
b. Time Delay 2 Sa 3.3.8.1.2 s8 3.3.8.1.3 A 21.5 seconds SR 3.3.8.1.4
3. 4.16 kV Emergency SuM Undervottage (Am* Ic ation)
a. Ilu Undervoltege 1 SR 3.3.8.1.1 i 3825 V SR 3.3.8.1.2 SR 3.3.8.1.3 S1 3.3.6.1.4 SR 3.3.8.1.2 s 60 seconds
b. Time Oelay SR 3.3.8.1.3 SA 3.3.8.1.4 HATCH UNIT 1 3.3-68A REVISION C

I UNITED STATES oNUCLEAR C REGULATORY COMMISSION WASHINGTON, D.C. 2W.omOi1 February 23, 1995 Mr. J. T. Beckham, Jr.

Vice President - Plant Hatch Georgia Power Company P. 0. Box 1295 Birmingham, Alabama 35201

SUBJECT:

SAFETY EVALUATION FOR DEGRADED GRID VOLTAGE RELAY SETPOINTS EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 (TAC NO. M80948)

Dear Mr. Beckham:

By letter dated July 1, 1994, you reqgested approval of a deviation from the current NRC staff position on degraded grid protection. This letter was a supplement to your November 22, 1993, letter which contained a description of your degraded grid protection system.

The staff has reviewed the above submittals and the information provided during our meetings on August 6, 1992, November 16, 1993, and December 7, 1994. Based on its review, the staff finds that your approach is acceptable as documented in the enclosed Safety Evaluation. This completes our action with respect to the above TAC. If you have any questions related to this matter, please contact me at (301) 415-1496.

Sincerely, Kahtan N. Jabbour, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366

Enclosure:

Sfety Evaluation cc w/encl: See next page CL I HATCH LICENSING &ENGNG

Mr. J. T. Beckhm, Jr.

Georgia Power Company Edwin 1. Hatch Nuclear Plant cc: Mr. Ernie Toupin Mr. Ernest L. Blake, Jr. Manager of Nuclear Operations Shaw, Pittman, Potts and Trowbridge Oglethorpe Power Corporation 2300 N Street, NW. 2100 East Exchange Place Washington, DC 20037 Tucker, Georgia 30085-1349 Mr. 0. M. Crowe Charles A. Patrizia, Esquire Manager Licensing - Hatch Paul, Hastings, Janofsky & Walker Georgia Power Company 12th Floor P. 0. Box 1295 1050 Connecticut Avenue, NW.

Birmingham, Alabama 35201 Washington, DC 20036 Mr. L. Sumner Mr. Jack D. Woodard General Manager, Nuclear Plant Senior Vice President -

Georgia Power Company Nuclear Operations Route 1, Box 439 Georgia Power Company Baxley, Georgia 31513 P. 0. Box 1295 Birmingham, Alabama 35201 Resident Inspector U.S. Nuclear Regulatory Commission Chairman Route 1, Box 725 Appling County Commissioners Baxley, Georgia 31513 County Courthouse Baxley, Georgia 31513 Regional Administrator, Region II U.S. Nuclear Regulatory Commission 101 Marietta Street, NW. Suite 2900 Atlanta, Georgia 30323 Mr. Charles H. Badger Office of Planning and Budget Room 610 270 Washington Street, SW.

Atlanta, Georgia 30334 Harold Reheis, Director Department of Natural Resources 205 Butler Street, SE., Suite 1252 Atlanta, Georgia 30334

UNITED STATES 0 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2056-6001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION DEGRADED GRID VOLTAGE RELAY SETPOINTS GEORGIA POWER COMPANY. ET AL.

EDWIN I. HATCH NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366 I. INTRODUCTION Georgia Power Company, et al. (GPC or the licensee) is proposing to deviate from the current NRC staff guidance provided in Generic Letters (GLs) dated 1977 and 1979 with respect to sustained degraded voltage conditions of the offsite power source and the adequacy of the station electric distribution system voltages (Reference 1). The GLs provided supplemental guidance to help ensure that all plants' electrical systems meet a staff interpretation of General Design Criterion (GDC) 17 regarding degraded'voltages.

The staff had concluded in 1982 that Hatch met the positions in the GLs (Reference 2). As part of the design approach, Hatch included a second level of degraded undervoltage protection with a nominal trip setpoint of 78.8% of bus voltage with a time delay of 21.5 seconds. CV-7 relays were used which have inverse time characteristics. Subsequently, an Electrical Distribution System Functional Inspection (EDSFI) determined that the voltage calculations done to support the setpoints were not adequate. Hatch was required to update the voltage calculations and the results indicated that the setpoint for the degraded grid protection should be raised to assure at least 91% voltage at the 4160 volt safety buses (Reference 3). Hatch investigated the feasibility of raising the setpoints at which automatic action would occur and concluded that the changes would involve new equipment and would be very costly.

Furthermore, they believed that raising the setpoint would not significantly improve safety and could lead to unwanted plant trips. As a result, they proposed an interim approach, which relied on maintaining the 230 kV switchyard voltage between 101.3% and 104.9% and included alarm relays set at a higher voltage level (about 92%) and associated manual actions. The staff approved the interim approach but requested that the licensee continue to investigate the matter. The licensee is now proposing the interim approach as the final resolution to meet the GLs.

Specifically, the licensee is proposing to maintain the existing setpoints for their automatic degraded voltage protection scheme and to rely on anticipatory alarms set at 92% and operator actions to provide protection. They believe that this approach provides the necessary protection and that the cost of changing equipment is not justified based on their conclusion that such changes would not improve safety.

By maintaining their Interim approach and not raising the setpoint for automatic action, it

, t rt4vn1eN, valteve94--p r .... ,'

,,-rmt, "6-Wpvtia d otv, This is considered a deviation from the GL positions, and therefore, the licensee has specifically requested that the staff approve the deviation.

In support of the deviation there have been a number of meetings and letters as listed below:

1. Meeting summary dated August 16, 1991, for the August 6, 1991, meeting.
2. Meeting summary dated December 21, 1992, for the November 16, 1992, meeting.
3. Letter from Georgia Power to NRC dated November 22, 1993.
4. Letter from Georgia Power to NRC dated July 1, 1994.
5. Meeting summary dated January 10, 1995, for the December 7, 1994, meeting.

II. EVALUATION The licensee's approach is based on their understanding of the events which led to issuance of the GLs and potential events which might challenge the Hatch facility. The GLs were prompted by events at Millstone One and Arkansas Nuclear One which heightened concerns for potential sustained degraded grid voltages and in plant voltage problems due to potential severe loading conditions during accidents.

The specific sequence of events which would require that the voltage setpoints be raised involves the simultaneous existence of a degraded offsite power source and a loss-of-coolant accident (LOCA). A LOCA puts the heaviest demand on the safety buses and if it would occur during degraded grid voltage conditions, some safety equipment might not receive sufficient voltage to perform their function. Among other requirements, the GLs required that the occurrence of a degraded offsite voltage should be sensed, and then an automatic transfer to the emergency diesel generators (EDGs) should take place. For the sequence of events of a degraded grid voltage and a LOCA, the licensee has concluded that the likelihood of such simultaneous events is extremely low. This is based on their existing grid operation coupled with the low likelihood of a LOCA.

Plant Hatch is part of the Southern electric grid system which is a member of the Southeastern Electric Reliability Council. The Southern electric system employs state-of-the-art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators of the Southern electric grid ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse effects from postulated grid system failures. Based on the contingency analysis results, system operators configure the offsite power system such that a worst-case postulated failure can occur without adversely affecting the minimum required voltage.

If the 230 kV system at Hatch were to fall below the current minimum expected value of 101.3%, the switchyard design and offsite power system design allows system operators to quickly mitigate such a dynamic voltage excursion. The following actions would be performed by system operators:

  • System operators receive low voltage alarm.

" System operators notify the control room at Plant Hatch.

" The 162 MVAR capacitor bank on the 230 kV line is switched on (if off).

" The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).

" Capacitor banks in the surrounding area are turned on (if off).

  • Combustion turbines at Plant McManus are placed in service.

These actions are normally capable of improving the 230 kW voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators would take the following actions:

" Out of service elements are brought back on line.

" System load (external or internal) is reduced.

Therefore, because of the above outlined offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion is more likely. For a dynamic voltage excursion, GPC believes that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety.

E** e!ntors,'f Soutbn electric grid fail t Jmrove the 23Q kV I , 1R has issoed an Operatinj Order at P1l aW which l s*e* f'9 actions to be taken if the grid system operators are in Je~~d'd~onot Wntatinng the Hatch voltages within the ,required operatdng qme. The actions consist of restoring any inoperable EDGs, limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on tIL.ix 4160 volt safety-related buses, and informing pTant management. Nov -Fu4jp__ . MU-_._

n s tet4et-to be performed tP the 460W volt ellsentil Nes al beelqw tJt h :MW*,,, ee, e v9"ge., These a%3.tie it c aidA*Alai* t* Wh L ting..Condition of wneent, and an 9W Yp70 '.ht-low ifWINUPS e .Th actions specified in the Operating Order have been incorporated into abnormal operating procedure 34AB-SII-001-OS, "Operation With Degraded System Voltage."

This procedure would also be entered on receiving the low voltage alarms on the 4160 volt buses. Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.

Therefore, the licensee concludes that, because of the elements in place on the Southern electric grid and at Plant Hatch, it would be a very rare event for the offsite voltage at Hatch to be below 101.3% during a postulated independent LOCA (from their RPE the estimated occurrence of a LOCA Is 2.61 x 10-4 for Hatch).

In response to NRC staff concerns, the licensee also investigated other potentially more likely events, and has concluded that the alarms and procedures along with the plant's inherent response capabilities provide sufficient protection.

1. Sustained degraded grid conditions (no LOCA or plant trip)

If the voltages on the offsite system were to degrade to unacceptable levels for a sustained period of time, the plant would be notified by the Southern System load dispatcher and in addition the plant alarms would alert the operators to the condition. Procedures would be implemented to restore voltages in one hour or start an orderly shutdown. By not raising the setpolnt at which automatic action would occur, some potential for unnecessary automatic unit trips could be avoided.

2. Dynamic voltage excursion (no LOCA or plant trip)

If the voltages on the offsite system were to degrade to the unacceptable level for a short period of time (on the order of minutes),

the plant would be notified by the Southern System load dispatcher.

Procedures would be implemented to restore the voltages. By not raising the setpoint at which automatic action would occur, unnecessary unit trips might be avoided. As noted by the licensee, an event of this nature occurred on Sunday, March 14, 1993. The licensee's post-event analysis concluded that this event supported its integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation. Details of the event and the licensee's analysis are provided in the appendix to this evaluation.

3. Sustained degraded grid conditions or a dynamic voltage excursion with Hatch units tripping (no LOCA)

If a plant trip occurred during a grid problem (which could reasonably be expected to occur due to problems related to the equipment exposed to the degraded voltages, or because the tripping of the Hatch units was part of the problem leading to the degraded grid voltage) operator response to correct the voltages might not be quick enough, and therefore, damage to some ac equipment could occur. In this situation, the licensee has analyzed their facility and concluded that equipment not exposed to the ac voltage problems (because it is operating on dc-backed sources or is not operating and, therefore, free from potential damage),

such as reactor core isolation cooling (RCIC) and high pressure coolant injection (HPCI) would be available to safely shut the plant down. This same kind of analysis was done as part of their Station Blackout analysis.

4. Sustained degraded grid conditions or dynamic voltage excursion with Hatch units tripping and then a stuck open relief valve (LOCA)

This event could be the most probable sequence involving a degraded grid and LOCA. Because the plant response would be the same (e.g., RCIC, HPCI) the same conclusions as the above event sequence would also apply.

The staff has evaluated the licensee's proposal and agrees with the approach with the following additional conditions:

-I'l The degraded voltage alarm relays should be included in the plant Technical Specifications along with the degraded voltage relays which initiate automatic actions.

1 The offsite system operating voltage levels and their significance with respect to the Hatch approach to meeting the degraded voltage requirements should be documented in the Final Safety Analysis Report so the impact of possible future changes will receive appropriate consideration.

The licensee has agreed to these added conditions.

W IerW~ approac Awiyitý~ sttr -and

-o-ta+/-~b~k,.nff

  • 4.5'SVW08I ' e¢c1 e,' 6t+t w W eO eapvbhiitt of p~444g.p~wer foo4ed-v eufeIopaet in.*4Ac ith GOC 11-Of W-GFR III. CONCLUSION Based on its review, the staff finds that the requested deviation from the Generic Letters is acceptable because of the added design features and the compensatory measures at Hatch as discussed in the above Safety Evaluation.

Principal Contributors: D. Thatcher N. Trehan Date: February 23, 1995

HFREENCES

1. a. June 2, 1977, NRC Generic Letter (Staff Positions) regarding the onsite emergency power systems.
b. August 8, 1979, NRC Generic Letter regarding the wAdequacy of Station Electric Distribution Systems Voltages.*
2. a. April 5, 1982, NRC Staff Safety Evaluation regarding the adequacy of electric distribution system voltages at Hatch Units 1 and 2.
b. May 6, 1982, NRC Staff Safety Evaluation regarding degraded grid Technical Specifications.
3. August 22, 1991, Electrical Distribution System Functional Inspection at Hatch, NRC Inspection Report No.91-202.

APPENDIX TEMPORARY VOLTAGE EXCURSION EVENT AT PLANT HATCH A temporary voltage excursion event occurred at Plant Hatch on Sunday, March 14, 1993. During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993, at 10:04 a.m.,

Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m.,

the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was-informed of the situation and confirmed that the Florida System was bringing up generation to stabilize the power flow from the Southern.System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery. The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.

Georgia Power's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt buses at Plant Hatch was not available, but no adverse effects were noted at the plant.

However, as part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room.

Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored. Technically, both units should have been in a one hour LCO.

The notification did not occur as system operations had concluded that the system was not in Jeopardy; the voltage excursion was quickly being restored.

Corrective actions were taken to clarify this requirement and assure proper communications.

4 The licensee concluded that this event demonstrated that the degraded grid protection for Plant Hatch is consistent with GPC's objectives.

" The plant was adequately protected from an undervoltage condition as no adverse effects were evident.

" The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.

" The situation was not further exacerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.

a If the setpoint for the degraded grid relays had been raised, a trip of Unit 1 probably would not have occurred for this specific event.

However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift. Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.

This led the licensee to conclude that the actual event supported GPC's integrated approach to evaluating degraded grid protection which considers electrical design requirements, plant operation, and grid system operation.

In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offslte power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductions/blackouts within the Southern Electric and Florida Power service areas would have been Increased.

. yTIO,*¶if'.

Georgia Power C.vgrpany

  • oo~l,, r~.,..r
  • 40 Inverness Center Parkway
  • PgsOttice Box 1295 Birmingham, Alabama 35201 Telephone 205 877-7279
a. T.5" aiJr. Georgia Power Vice Pesident - Nuclear Hatch Project the sOhew electrc system July 1, 1994 Docket Nos. 50-321 HL4586 50-366 TAC No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1.Hatch Nuclear Plant Degmaded Grid Protection Gentlemen:

Following the electrical distribution system functional inspection which was completed on July 12, 1991, Georgia Power Company (GPC) representatives and the Nuclear Reactor Regulation (NRR) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. By letter dated November 22, 1993, GPC submitted a description of an evaluation which concluded that the existing degraded grid protection system provides an adequate level of safety and is in compliance with applicable regulations.

The degraded grid protection system was originally established in response to the Nuclear Regulatory Commission's letter dated June 2, 1977. This letter requested GPC to compare the design of the emergency power systems with the staff positions stated in the letter's enclosure to assess the susceptibility of the safety-related electrical equipment with regard to a sustained degraded voltage condition at the offsite power sources and interaction between the offsite and onsite emergency power systems. These staff positions, which were the precursors to Branch Technical Position PSB-1, are provided on page E-2 of GPC's November 22, 1993 submittal.

'-,orgla Power A U.S. Nuclear Regulatory Commission Page Two July 1, 1994 An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between approximately 91 percent (3786 volts) and 88.34 percent (3675 volts), certain class IE loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.

GPC's analysis of expected voltages for the safety-related loads uses the minimum expected voltage from the off'ite power supply rather than the setpoint for the degraded grid undervoltage relay. 'As a result, a "deadband" exists between the minimum required voltage on the 4160 volt safety-related busses and the setpoint of 88.34 percent of 4160 volts for initiating an automatic disconnect of the offsite power supply. Consequently, a deviation from the staff position stated in the June 2, 1977 letter exists relative to ihe initiation of an automatic disconnect from the offsite power source. The deviation is approximately 12 percent when comparing the minimum required voltage to the voltage and time delay stated in the Technical Specifications, which is 78.8 percent of 4160 volts at 21.5 seconds. These setpoints are specified in Table 3.2-12, and Table 3.3.8-1 of the Unit I and Unit 2 Technical Specifications, respectively.

GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. As described in GPC's November 22, 1993 submittal, the inputs are the electrical requirements of safety related equipment, the high reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA). Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded grid voltage protection at Plant Hatch provides adequate assurance of plant safety. As a result, the existing degraded grid protection system uses manual actions instead of an automatic disconnect in the range of the deadband. Accordingly, GPC has implemented an abnormal operating procedure to provide specific actions to address a degraded offsite power supply. If the 4160 volt bus voltages were to degrade below approximately 92 percent, operators will initiate a "one hour to restore" action statement. If voltages are not restored within one hour, a plant shutdown is then initiated.

F' orgia Pwer A U.S. Nuclear Regulatory Commission Page Three July 1, 1994 During recent discussions, the NRR staff requested GPC to incorporate the degraded grid alarms into ths Technical Specifications for both units. In response, GPC has agreed to include the alarms, along with the degraded grid undervoltage relays, in the improved Technical Specifications. Accordingly, the limiting condition of operation (LCO) will require the degraded grid Wjarms to be operable in modes 1,2, and 3. The specification will include two actions. One will require monitoring the associated 4160 volt bus voltage on an hourly basis if one or more degraded grid alarms are inoperable. Each 4160 volt bus has two alarm relays. The second action will be to restore the inoperable alarm during the next refueling outage. The specification will also include a surveillance to perform an instrument calibration at least once per operating cycle.

Additionally, the NRR staff has verbally requested GPC to consider raising the degraded grid alarm setpoints from their current value of approximately 92 percent of 4160 volts to approximately 97 percent of 4160 volts. The current degraded grid alarm setpoints are specific to the individual 4160 volt busses and range from approximately 92 to 93 percent of 4160 volts. The NRR staff expressed a concern that an alarm setpoint of 92 percent would not provide sufficient notification that the voltage required for (LOCA) conditions had been degraded. GPC has evaluated this request to raise the alarm setpoints to 97 percent of 4160 volts and determined that it is not feasible nor required. The basis for this conclusion is as follows:

The NRR staffs request, basically, corresponds to applying the "hypothetical" alarm and trip ranges. That is, the range between the minimum expected operating voltage and the minimum required for LOCA conditions is sufficiently wide to accommodate an alarm and a trip prior to reaching the minimum required. As described on page E-9 of GPC's November 22, 1993 letter, the existing narrow range between the voltage expected with the offsite power at 101.3 percent of 230 Kv and the minimum required for LOCA loads would not accommodate an alarm setpoint of 97 percent due to the voltage changes associated with normal and startup/shutdown bus alignments to the startup transformers.

As a result, an alarm setpoint of 97 percent would be expected to generate frequent nuisance alarms when the non-safety 4160 volt busses are powered from the startup transformers with the offsite power at 101.3 percent of 230 Kv.

'orgia PowerA U.S. Nuclear Regulatory Commission Page Four July 1, 1994

  • The current alarm setpoints of approximately 92 to 93 percent of .4160 volts are approximately midway between the calculated minimum expected voltage with the offsite power at 101.3 percent and the calculated minimum required voltage for normal operating conditions. The current alarm setpoint values signify that adequate voltage is available for normal operations. Consequently, the annunciator response procedures direct the operators to confirm the low voltage condition, contact the GPC control center, and to enter procedure 34AB-SI 1-001 -OS, "Operation With Degraded System Voltage" if the voltage cannot be restored. Procedure 34AB-Sl 1-001-OS directs operators to initiate a "one hour to restore" action statement for restoring the bus voltages to acceptable levels for normal operation. An alarm at 97 percent would not necessarily signify that a degraded voltage condition existed depending on the bus alignments to the startup transformers. From a human factors perspective, the significance of the alarm would be reduced as operators would expect to receive the alarm in certain conditions.

Additonally, the current "one hour to restore" action statement significance would be inappropriate for the higher alarm setpoint. Consequently, the setpoints for the degraded grid alarms consider voltage requirements for normal operation as opposed to voltage requirements for LOCA conditions as the probability of a sustained degraded grid event concurrent with a LOCA is extremely low and is not a credible event.

Since GPC's alternate methodology of using manual actions instead of an automatic disconnect differs from the staff position stated in the June 2, 1977 letter, GPC requests formal NRR staff review and approval of this deviation. As described in the November 22, 1993 submittal, GPC has evaluated the deviation from the staff position and concluded that the existing degraded grid protection system is adequate, and is in conformance with applicable regulations. GPC has determined that the deviation is acceptable based on the offsite power system monitoring, the reliability of the offsite power supply, the extremely low probability of a sustained degraded grid event concurrent with a LOCA, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, the impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event, and the enhancements provided by operating orders and degraded grid alarms.

~,

'orgia PbwerA U.S. Nuclear Regulatory Commission Page Five July 1, 1994 Should you have any questions in this regard, please contact this office.

Sincerely, L.T.Beckliarn. Jr.

JKB/cr cc: GeorigaPowerCorM~v Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. NuclearRegulator Commission, Washingon, D.C.

Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. Nuclear Regulator Commission. Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. B. L. Holbrook, Senior Resident Inspector - Hatch

Gworg~Powor Comparvy 40 Invunm Cente Palway a

Post Office Box 1295 Birmingham, Alabama 35201 Telephwwi 205 877-7279 J. T.

Vim President

Hatch Project f~ soumnern evc:',,; ."

November 22, 1993 Docket Nos. 50-321 HL-4440 50-366 Tac No. 80948 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Degraded Grid Protection Gentlemen:

On previous occasions, Georgia Power Company (GPC) representatives and the Nuclear Regulatory Commission (NRC) staff have held meetings and telephone conference calls to discuss the performance and protection of safety-related equipment at the Edwin I. Hatch Nuclear Plant during postulated degraded grid voltage conditions. The degraded grid protection issue resulted from an electrical distribution system functional inspection which was completed on July 12, 1991.

During these meetings and conference calls, GPC discussed the objectives, criteria, and actions taken to resolve the degraded grid issue at Plant Hatch. GPC has assessed the level of safety provided by the current system and investigated options and potential modifications to upgrade the existing system. As a result, GPC has determined that the existing degraded grid protection provides adequate protection and is in accordance with the provisions of an NRC Safety Evaluation Report issued on May 6, 1982. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. Consequently, the extensive plant modifications required to eliminate the narrow voltage deadband are unnecessary and unwarranted.

Modifying the plant in this manner is unnecessary as there is no discernible increase in the protection of the health and safety of the public.

As described in the enclosure, GPC's analysis of the degraded grid protection system determined that the evaluation requires consideration of several inputs. The principal inputs involved are the electrical requirements of safety-related equipment, the reliability of the offsite power supply, the potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source, and the extremely low probability of a sustained degraded grid concurrent with a loss of coolant accident (LOCA).

Qargia Pbwer U.S. Nuclear Regulatory Commission ,Page Two November 22, 1993

.Because of the offsite system monitoring, contingency analysis, and transmission system design and operation, the occurrence of a sustained degraded grid condition requiring disconnect, concurrent with a LOCA, is not considered a credible event. Additionally, the existing narrow range between the minimum expected voltage and the voltage required for LOCA loads is insufficient to allow an increase in the undervoltage relay setpoints.

Consequently, an increase in the undervoltage relay setpoints would likely result in an unnecessary and unwanted disconnect from offsite power during a LOCA. The possibility of spurious disconnects would also be increased. In order to increase the available range between the minimum expected and minimum required voltage, a large investment in extensive plant modifications would be required. Also, replacing the existing CV-7 inverse time relays with discrete time relays at the existing setpoint would not resolve the deadband issue. Given the adequate level of safety provided by the existing system, GPC does not consider such expenditures to be warranted or necessary. Consequently, GPC does not consider further actions to be necessary.

The enclosure provides additional details regarding GPC's evaluation and formal documentation of the positions expressed by GPC in discussions with the NRC staff.

Upon review, GPC is requesting NRC staff concurrence with these actions as representing closure for the degraded grid issue at Plant Hatch.

Sincerely, 6.T. Beckham, Jr.

JKB/cr 004440

Enclosure:

Degraded Grid Voltage Protection cc: (See next page.)

Georgia Power A U.S. Nuclear Regulatory Commission Page Three November 22, 1993 cc: GeorgiaPower Comvanv Mr. H. L. Sumner, Nuclear Plant General Manager NORMS US. Nuclear ReBuMaLoq Commission. Washingon. D.C.

Mr. K. Jabbour, Licensing Project Manager - Hatch U.S. NuclearRe*,ulator Commission. Region 11 Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch

Enclosure Edwin I. Hatch Nuclear Plant Degraded Grid Voltage Protection The existing degraded grid undervoltage protection system and setpoints were established and approved in response to a Nuclear Regulatory Commission (NRC) generic letter issued on June 2, 1977. During the Summer 1991 Electrical Distribution System Functional Inspection at Plant Hatch, the NRC inspection team questioned whether, under postulated degraded grid conditions, the setpoints of the undervoltage relays on the 4160 volt safety-related buses were too low to prevent the voltage on the 600 volt and 208 volt buses from dropping below minimum required voltages prior to disconnecting from the offsite power system. In response to this issue, Georgia Power Company (GPC) implemented an Operating Order as an interim measure. As a result of subsequent discussions with the NRC staff, one permanent modification to the degraded grid undervoltage protection system, as established in 1982, has been implemented to augment the protection provided. This modification installed an anticipatory alarm to alert plant operators of marginal voltages and augments the existing transmission system voltage monitoring scheme. Additionally, the provisions of the operating order have been incorporated into a permanent plant procedure.

Oriin of the Issue The requirements for undervoltage relay protection originated as the result of an event at Northeast Utilities' Millstone Unit 2. On July 5, 1976, several 480 volt motors failed to start following a trip of Millstone Unit 2. The failure to start was the result of blown control power fuses on the individual motor controllers. An investigation at Millstone showed that the offsite power voltage dropped approximately 5 percent from 352 Kv to 333 Kv subsequent to the trip of the Millstone unit. The voltage drop reduced the control power and voltage within the individual 480 volt controllers to a voltage which was insufficient to actuate the contactors. As a result, the control power fuses were blown when the 480 volt motors were signaled to start.

At the time, Millstone's undervoltage protection consisted of only loss of offsite power undervoltage relays to separate the plant from the grid and initiate the onsite power sources. Millstone's initial corrective action was to raise the setpoint of these relays.

However, this action was later considered inappropriate when the voltage dropped below the setpoint during starting of a large circulating water pump and de-energized the emergency buses.

HL-4440 E-1

PI-'

Enclosure Degraded Grid Voltage Protection In response to the event at Millstone, by letter dated June 2, 1977, the NRC requested GPC to assess the susceptibility of safety related electrical equipment to a sustained voltage degradation of the offsite source. The letter contained positions with which the design of the plant was to be compared. These positions were the precursors to a branch technical position and are as follows:

1. "The selection of voltage and time setpoints shall be determined from an analysis of the voltage requirements of the safety related loads at all onsite distribution system levels."
2. "The voltage protection shall include coincidence logic to preclude spurious trips of the offsite power sources."
3. "The time delay selected shall be based on the following conditions:
a. The allowable time delay, including margin, shall not exceed the maximum time delay that is assumed in the FSAR accident analysis."
b. "The time delay shall minimize the effect of short-duration disturbances from reducing the unavailability of the offsite power source(s)."
c. "The allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety systems or components."
4. "The voltage monitors shall automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time-delay limits have been exceeded."
5. "The voltage monitors shall be designed to satisfy the requirements of IEEE Standard 279-1971.
6. "The technical specifications shall include limiting conditions for operations, surveillance requirements, trip setpoints with minimum and maximum limits, and allowable values for the second-level voltage protection monitors."

IHL-4440 E-2

Enclosure Degraded Grid Voltage Protection GPC provided an initial response on July 22, 1977, and additional information and Technical Specifications changes on October 9, 1980 and May 21, 1981. GPC submitted modified Technical Specifications changes on October 2, 1981 and December 2, 1981.

Additional information is contained in GPCs submittals dated September 17, 1976; January 12, 1982; and January 26, 1982. Also, a brief description of the electrical distribution system for Plant Hatch is provided in Attachment 1.

GPC's methodology in addressing the NRC positions used the maximum plant loading conditions to determine the minimum expected voltage from the offsite power supply. At the time, the minimum expected value was 98 percent of 230 kV. Periodic, later evaluations have been performed to revise the minimum expected value as needed. GPC recalibrated one set of undervoltage relays to initiate transfers of the offsite power source to protect against a degraded grid. The Technical Specifications amendment request pertaining to degraded voltage protection was reviewed by the NRC staff and approved by letter dated May 6, 1982.

EDSFI and Degraded Voltage Protection Reevaluation An electrical distribution system functional inspection (EDSFI) was performed at Plant Hatch from June 10 through July 12, 1991. The NRC team determined that during a postulated design basis loss of coolant accident concurrent with the 4160 volt bus voltage in a narrow 3% band between 91 percent (3786 volts) and 88.34 percent (3675 volts),

certain class 1E loads at voltage levels of 600 volts and below may not receive sufficient voltage. The NRC EDSFI team did not agree with GPC's methodology which established a minimum expected value for offsite power to ensure adequate voltage and concluded that the automatic degraded grid protection was not adequate.

By letter dated October 7, 1991, the NRC issued a Level IV violation stating that the automatic undervoltage protection for degraded grid voltage was not adequate to ensure that accident mitigating equipment would receive sufficient voltage to perform their safety function. By letter dated November 6, 1991, GPC denied the violation associated with degraded grid protection. GPC concluded that a violation of NRC requirements did not exist based on the following:

HL-4440 E-3

Enclosure Degraded Grid Voltage Protection

1. The existing degraded grid protection scheme at Plant Hatch is in accordance with GPC's response to the NRC Generic Letter dated June 2, 1977. As part of GPC's response to the NRC staff positions concerning degraded grid protection, a range for offsite voltage was established and shown to adequately supply emergency loads.
2. Compliance with the method of using the minimum expected voltage for the offsite grid in establishing the adequacy of plant voltage levels has been maintained. In the original voltage study submitted to the NRC on October 9, 1980, a minimum offsite source operating voltage of 98 percent of 230 kV was expected. At that time, the tap setting for transformer "D" was 1.0 p.u. (i.e., for a system voltage of 98% of 230 kV the corresponding voltage on the 4160 V buses for no-load conditions was 98% of 4160 V). The current minimum expected value is 101.3 percent of 230 kV. However, the increase was not a result of load additions to the plant. Rather, the change was necessary to accommodate higher expected transmission system operating voltages.

Consequently, tap changes were made for the startup transformers in 1986 and 1987.

Presently, the tap setting for transformer "D" is 1.025 p.u. (i.e., for a system voltage of 101.3% of 230 kV the corresponding voltage on the 4160 V bus for no-load conditions is 98.8% of 4160 V). Using the present minimum expected source voltage, tap connections, and load configurations, the expected 1E system voltages are, generally, slightly higher than the bus voltages submitted in 1980.

3. The existing degraded grid undervoltage relay setpoints were approved in the Safety Evaluation Report dated May 6, 1982. The SER affirmed compliance with staff positions for a second level of undervoltage protection.
4. Given the elapsed time since the original submittal in 1980, GPC has reevaluated the adequacy of the degraded grid protection at Plant Hatch. GPC's objectives were to assess the level of safety provided by the current system, investigate available options, and determine if improvements are feasible. GPC has concluded that the existing protection is adequate, raising the undervoltage relay setpoints is not feasible, and replacing the CV-7 relays with discrete time relays would repreient a marginal to safety improvement. This conclusion is based on the following:

A. The event at Millstone was significant in that a plant trip and the corresponding loss of electrical generation resulted in a sustained degraded offsite power supply without operator awareness of the event. However, significant differences exist between Plant Hatch and Millstone. The Southern electric system employs state-

-L-4440 E.4

Enclosure Degraded Grid Voltage Protection of-the art monitoring and contingency analysis systems for the electric grid on a real time basis. System operators ensure that adequate voltage is provided and the contingency analysis feature allows system operation to predict adverse affects from postulated system failures. Based.on the contingency analysis results, system operators configure the offsite power system such that a worst case postulated failure can occur without adversely affecting the minimum required voltage. If the 230 kV system were to fall below the current minimum expected value of 101.3 percent, the switchyard design and offsite system design allows system operators to quickly mitigate a dynamic voltage excursion. Such an event actually occurred in March 1993 which is discussed later. This design allows the following actions to occur if the system were to fall below 101.3 percent. These following actions should be performed by system operators within approximately 10 minutes.

" System operators receive low voltage alarm.

" System operators notify the control room at Plant Hatch.

" The 162 MVAR capacitor bank on the 230 kV switchyard is switched on (if off).

" The 150 MVAR shunt reactors on the 500 kV line are turned off (if on).

" Capacitor banks in the surrounding area are turned on (if off).

" Combustion turbines at Plant McManus are placed in service.

These actions are normally capable of improving the 230 kV voltage by approximately 2 to 4 percent. If these actions are not sufficient, system operators will take the following actions:

  • Out of service elements are brought back on line.

" System load (external or internal) is reduced.

Consequently, based on the system monitoring capabilities, contingency analysis capabilities, operation of the system such that a postulated worse case failure will not impact the offsite voltage below the minimum required, and the ability for system operators to quickly restore a dynamic voltage excursion; the event at Millstone is not considered applicable to Plant Hatch.

HL-4440 E-5

Enclosure Degraded Grid Voltage Protection B. Because of the offsite system monitoring capabilities and design, a sustained degraded grid does not represent the most probable event. Rather, a dynamic voltage excursion lasting less than 10 minutes is more likely. Consequently, the degraded voltage protection at Plant Hatch provides adequate assurance of plant safety for this type of event. For a dynamic voltage excursion, GPC has determined that disconnecting both units from the offsite power supply and introducing dual unit scrams and reactor isolation transients through automatic undervoltage relays would be adverse to safety. GPC initially issued an Operating Order which identified specific actions to be taken if the system operators are in jeopardy of not maintaining voltages within the required operating range. The actions consist of restoring any inoperable emergency diesel generators (EDGs),

limiting maintenance or surveillance of important onsite electrical equipment, closely monitoring voltage levels on the six 4160 volt safety-related busses, and informing plant management. The Operating Order also specified actions to be performed if the 4160 volt essential busses fall below the minimum acceptable voltage. These actions include initiation of a one hour Limiting Condition of Operation (LCO) to restore safety-related bus voltages, notification of management, and an orderly plant shutdown if voltage is not restored. The actions specified in the operating order have been incorporated into abnormal operating procedure 34AB-S11-001-OS, "Operation With Degraded System Voltage."

Operators receive training relative to the actions specified in the procedure through the normal operator training and operator requalification training on abnormal operating procedures.

This alternate method allows system operators to quickly restore a degraded grid to avoid an unnecessary isolation transient, further degradation of the offsite power supply to the plant, adverse impacts to neighboring utilities and other interconnected plants, when the offsite power is undergoing a temporary voltage excursion and is not in actual jeopardy.

An event as described above actually occurred at Plant Hatch on Sunday, March 14, 1993.

During that weekend, record snow accumulations, along with high winds were occurring within the Southern Electric System. This was resulting in significant outages due to failures of local distribution networks. During this time, specifically on March 14, 1993 at 10:04 a.m., Florida Power Corporation's Crystal River Unit 2 tripped. The loss of generation within the Florida grid caused a dynamic voltage excursion within the Southern HL-4440 E-6

Enclosure Degraded Grid Voltage Protection Electric grid. The Hatch switchyard voltage dropped to 215 kV (93 percent) in one second and stabilized at 223 kV (97 percent) in approximately 6 seconds. At 10:05 a.m., with the Hatch switchyard voltage at 223 kV and recovering, Crystal River Unit 4 tripped. The second loss of generation resulted in a voltage drop to 218 kV (95 percent). At 10:06 a.m., the Southern Company Power Control Center contacted the Florida Power Control Center to assess the conditions causing the voltage excursion and the condition of the Florida grid. Southern Company was informed of the situation and confirmed that the Florida system was bringing up generation to stabilize the power flow from the Southern System to Florida's grid. Approximately 1.5 minutes after Crystal River Unit 4 tripped, the Hatch capacitors were manually closed and the voltage began a steady recovery.

The combined voltage excursion from both the Crystal River Unit 2 and Unit 4 trips lasted approximately 6.5 minutes.

GPC's review of the event concluded that the system performed as expected given the transmission system failures caused by the snow storm and nearly simultaneous unit trips at Florida Power. The loss of generation within the Florida System caused a voltage depression throughout the south Georgia area as the power flow from the Southern System to the Florida System increased to replace the lost generation. The actual effect or drop in voltage on the 4160 volt busses at Plant Hatch is not available; however, none of the anticipatory degraded grid alarms actuated indicating that the voltage did not drop below the minimum required for normal operation for a sufficient time to exceed the relay's time delay.

As part of the review, GPC identified a discrepancy relative to communication between the system operators and the Hatch control room. Specifically, system operators did not notify the Hatch control room that the 230 kV voltage had dropped below the minimum value until after the voltage had been restored.

Technically, both units should have been in a one hour to restore LCO as specified by the operating order. The notification did not occur as system operations had concluded that the system was not in jeopardy, the voltage excursion was quickly being restored, and the brief time of the excursion. Corrective actions have been taken to clarify this requirement and assure proper communications.

HL-4440 E-7

Enclosure Degraded Grid Voltage Protection This event demonstrates that the existing degraded grid protection for Plant Hatch is consistent with GPC's objectives.

0 The plant was adequately protected from an undervoltage condition as no alarms were actuated and no adverse effects were evident.

  • The offsite power source was preserved as the preferred source. While a short term dip in voltage occurred, the integrity of the system was not in jeopardy and a disconnect was not warranted.

0 The situation was not further exascerbated by the unnecessary removal from the grid of Unit l's approximately 800 megawatts. (Unit 2 was in a fuel reconstitution outage). Accordingly, the Southern Electric System was able to provide support to the Florida Power System as needed.

  • If the setpoint for the degraded grid relays had been raised, a trip of Unit I probably would not have occurred. However, the possibility of an unnecessary disconnect would have been increased due to possible setpoint drift.

Consequently, GPC's objective of avoiding an unnecessary reactor isolation transient was met.

The actual event supported GPC's integrated approach to evaluating degraded grid protection which considered the electrical design requirements, plant operation, and system operation. In the event, the plant's electrical equipment was not adversely impacted by the voltage excursion, the plant continued to support the grid, the Southern Electric grid was able to support a neighbor utility and its public, and the plant was able to remain on offsite power. However, the application of automatic controls or prescriptive actions, in this event, could have been adverse to safety as the possibility of unnecessarily disconnecting the plant from the offsite power supply would have been increased, the possibility of unnecessary reactor isolation transients would have been increased, and the possibility of unnecessary load reductionstblackouts within the Southern Electric and Florida Power service areas would have been increased.

C. GPC has investigated options and potential modifications to improve the existing system. Based on the results, GPC has concluded that modifications in addition to the anticipatory alarms recently installed are not desirable. This conclusion is based on the following:

HL.-4440 E-8

Enclosure Degraded Grid Voltage Protection To meet a hypothetical alarm/trip range scheme as shown on Attachment 2, a large investment in major equipment and/or extensive plant modifications would be required. GPC has estimated the cost at approximately 10 million dollars. Given the level of safety provided by the existing system, such an expenditure is not warranted.

Because of the existing narrow range between the voltage expected with the offsite power at 101.3 percent and the minimum required for LOCA loads, it would not be advisable to raise the setpoints for the undervoltage relays on the E, F, and G 4160 volt busses. As shown in the voltage diagrams for the safety-related 4160 volt buses provided as Attachment 3, the G bus on Unit I represents the bus with the most narrow range between the minimum expected and the minimum required voltage. With the offsite power at 101.3 percent and loads associated with mitigating a design basis LOCA being supplied, the G bus is expected to be at 91.14 percent. However, the minimum required to ensure adequate voltage is supplied is 90.8 percent. Consequently, a band of 0.34 percent is available. Since the most accurate undervoltage relay evaluated has an accuracy of approximately 1.25 percent, the trip may occur within the expected voltage. This could result in an unnecessary and unwanted disconnect from offsite power during a LOCA which is contrary to applicable NRC staff positions for minimizing the unavailability of the offsite power source. Due to the narrow band, the anticipatory degraded grid alarm recently installed is expected to annunciate if the grid is at 101.3 percent concurrent with a LOCA. Raising the undervoltage relay setpoint would introduce a consequence which is contrary to the NRC staff positions for degraded voltage protection. As stated previously, increasing the range between the minimum expected and minimum required voltages as shown in Attachment 2 would require purchasing major equipment and/or extensive plant modifications. Given the existing level of protection and the cost for installing new startup transformers, plant modifications, or switchyard equipment, the improvement would be costly and minimal to safety improvement.

GPC has also investigated the benefits associated with replacing the existing CV-7 inverse time relays with discrete time relays without raising the setpoint. While new relays could resolve the concern relative to potentially excessive delays in the transfer of the 4160 volt bus to the onsite power supply once the setpoint is reached, new relays will not provide a resolution to the deadband issue. The setpoint for the new relays would be the same as the existing setpoint and the HL-4440 E-9

Enclosure Degraded Grid Voltage Protection minimum required voltage would be unaffected. Given that the substantive issue of the deadband would not be resolved, GPC considers the installation of discrete time relays to be an unwarranted expenditure.

Conclusion GPC's analysis of the degraded grid protection concluded that the evaluation requires consideration of several inputs. The primary inputs into GPC's evaluation involved:

" The electrical requirements of safety-related equipment.

  • The reliability of the offsite power supply.
  • The potential adverse effects to the plant caused by an unnecessary disconnect from the offsite power source.

" The extremely low probability of a sustained degraded grid event concurrent with a LOCA.

  • The impact to the offsite power system caused by separating up to 1600 MW during a degraded grid event.

As a result of the reevaluation, GPC has concluded that the existing degraded grid protection provides an adequate level of safety. Additionally, the degraded grid protection has been augmented by the installation of anticipatory alarms and an abnormal operating procedure. GPC also concluded that raising the setpoints for the undervoltage relay to the minimum required voltage level would fikely result in an unnecessary disconnect from offsite power during a LOCA with the grid at 101.3 percent of 230 kV. The modifications necessary to increase the available range between the minimum expected and minimum required, such that unwanted or unnecessary disconnects are precluded, would be costly and marginal to safety. Given the adequate level of safety provided by the existing system, GPC does not consider further expenditures to be necessary.

HL-4440 E-10

ATFACHMENT I EDWIN I. HATCH NUCLEAR PLANT ELECTRICAL DISTRIBUTION SYSTEM DESCRIPTION

Attachment I Edwin I. Hatch Nuclear Plant Electrical Distribution System Description Electrical Distribution System Description for Plant Hatch The Georgia Power Company (GPC) grid is a network of many interconnections with other utilities and multiple locations for tying generating plants into the grid system.

The GPC system is also designed to connect generating units to the grid at optimum locations. This is evident at Plant Hatch as eight transmission lines from different locations and directions tie the units to the grid.

The switchyard at Plant Hatch consists of four 230 kV lines and four 500 kV lines. The Unit I main generator is connected to the 230 kV portion of the switchyard and the Unit 2 generator is connected to the 500 kV portion of the switchyard.

The following is a discussion of the electrical distribution system and is applicable to either unit. A simplified one line diagram is provided inFigure 1.

Four transformers supply power to the distribution system for each unit. Normally, transformers A and B are used when the unit is on line and supply power from the main generator to non-safety related 4160 volt busses A, B, C, and D. Transformers C and D supply power from the 230 kV switchyard to safety related busses E, F, and G and also supply non-safety related busses A, B, C, and D during startup and shutdown.

The 4160 volt busses A and B supply power to the reactor recirculation pumps and the condenser circulating water pumps which are the plant's largest loads.

The 4160 volt busses C and D supply power to various auxiliary loads such as the condensate and condensate booster pumps within the feedwater system, as well as the majority of the non-safety related loads at the plant.

The 4160 volt E, F, and G busses supply power to the unit's safety related loads such as the core spray pumps, RHR pumps, plant service water, and RHR service water pump motors, as well as safety related 600 volt and lower busses. These are the busses backed up by the diesel generators.

HL-4440 A-I

Attachment I Electrical System Description During startup, non-safety related 4160 volt busses A and B are supplied from offsite power through transformer C. After the main generator is synchronized and the loads are stable, a synchronized transfer normally is made to transformer B. If transformer B is lost, a "fast" transfer is made back to transformer C. If startup transformer D is out of service, this transfer is blocked because the safety related busses will be transferred to transformer C. Additionally, busses A and B would be tripped if already connected.

During startup, non-safety related 4160 volt busses C and D are connected to startup transformer D. After synchronization, these busses are normally transferred to transformer A. Transformer D is sized to carry the required loads for busses E, F, G, C, and D.

During startup, shutdown, and normal operation, safety related 4160 volt busses E, F, and G are normally supplied from startup transformer D. If transformer D fails, there is an automatic transfer to startup transformer C. If both transformer D and C fail, the emergency diesel generators are connected to 4160 volt busses E, F, and G.

BL-4440 A-2

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1" -9950 - UNIT I MI" POE DaSIRrnjllI MIN PmfR DISIIO I'H-2350 - UNIT 2 - .,,,2 FIGURE 1 MAIN POWER DISTRIBUTION SYSTEM BREAKER POSITIONS - NORMAL OPERATION

ATTACHMENT 2 EDWIN 1. HATCH NUCLEAR PLANT HYPOTHETICAL ALARMJTRIP RANGES

HYPOTHETICAL ALARM / TRIP RANGES NUEFXPECTED VOLTAGE A SETPOINT TRIP SETPOINT

?IN REQUnRED VOLTAGE I

ATTACHMENT 3 EDWIN I. HATCH NUCLEAR PLANT 4160 VOLT BUS VOLTAGE DIAGRAMS

PLoant Ha~tch .Unit 1 Bus E 98.2 EXP 104.9 103.5 101.3 ALARM 91.24 REQ E DEAD BAND CALC. 92764PG

Plant Hatch Unit 1 BusF 97.6 EXP 104.9 103.5 101.3 1~~~~

ALARM 88.47 REQ EmDEAD BAND CALC. 92764PG I

Plant Hatch Unit 1 Bus 0 4.16KV 230KV 104,9 ", 97.6 EXP 103.5 --

101.3 ALARM 91.4 REQ 91.14 EXP 90.80 RED 88.34 LDEAD BAND CALC, 92764PG

Plaxnt Ha~tch Unit Bus E 97.85 EXP 104.9 103.5 101.3 ALARM 90.73 REO MDEAD BAND CALC. 92763PG

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