ML20134N786
| ML20134N786 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 02/18/1997 |
| From: | Thompson H NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| To: | |
| References | |
| SECY-97-042, SECY-97-042-R, SECY-97-42, SECY-97-42-R, NUDOCS 9702240449 | |
| Download: ML20134N786 (53) | |
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!l dat6 inda s e e e e e e e e e e s e o > e e e e!S s
eese POLICY ISSUE (Information)
Fe'ruary 18, 1997 sECY-97-042 u
FOR:
The Commissioners i
FROM:
Hugh L. Thompson. Jr.
Acting Executive Director for Operations
SUBJECT:
RESPONSE TO OIG EVENT INQUIRY 96-045 REGARDING MAINE YANKEE PURPOSE:
To inform the Commission of the staff's actions to address the findings of the report of the Office of the Inspector General (0IG) entitled "The NRC Staff's Actions Related to Regulation at Maine Yankee."
BACKGROUND:
By memorandum dated May 8. 1996, the Inspector seneral submitted to the Commission the results of its event inouiry concerning the NRC staff's actions associated with small break loss-of-coolant accioent (SBLOCA) analyses of the emergency core cooling systems (ECCS) to support two amendments increasing the rated thermal power at wnich Maine Yankee Atomic Power Station (MYAPS or Maine Yankee) could operate. The OIG inquiry was initiated as a result of an allegation in December 1995 regarding certain SBLOCA analyses for MYAPS performed by Yankee Atomic Electric Company (YAEC) for Maine Yankee Atomic Power Company (NYAPCo).
In SECY-96-135. " Response to Event Inquiry - Maine Yankee Atomic Power Station (Case No.96-045)." dated June 21, 1996, the staff informed the Commission of its plans to address the findings of the May 8, 1996. 0IG report entitled "The NRC Staff's Actions Related to Regulation at Maine Yankee." In SECY-96-135. the staff committed to report the results of its reviews and the status of the staff's corrective actions to the Commission.
NOTE: To BE MADE PUBLICLY AVAILABLE IN 5 WORKING DAYS FROM THE DATE OF THIs PAPER CONTACT:
kdpt Danicl H. Oorman. NRR j
(301) 415-1429
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DISCUSSION:
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Recognizing the potential for safety conerns similar to those regarding SBLOCA analyses and power uprates at Mair.e Yankee arising at other power reactors, the staff started in~ early 1996 to address many of the issues l
subsequently raised in the OIG report. A team was formed within the Office of l.
Nuclear Reactor Regulation (NRR) to determine the. lessons learned from the l
l problems identified with the. ECCS analysis for MYAPS and to provide recommendations for improving the staff's processes. The team's )lan was attached to SECY-96-135. This team was directed to address (1) tie technical 1
review processes for computer code applications and for power uprate amendment i
requests: (2) coordination between technical and projects staffs, including l
technical staff concurrence: (3) delegation of signature authority:
(4) tracking and verification of licensee commitments: and (5) closecut of selected Three Mile Island (THI) Action Plan items at other power reactors for j
potential vulnerabilities similar to those identified in the Maine Yankee case. On May 8, the OIG issued its report. Team activities continued and the j
team's plan formed the basis for SECY-96-135.
The OIG report documented nine observations.
In SECY-96-135, the staff specifically addressed OIG Observation No. 4. i.e., that NRC staff on
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distribution for NRC correspondence had the opportunity to question that l
correspondence. The team's report, dated December 1996. (Attachment 1)
L addresses the issues raised in the remaining observations. Some of the team's l
recommendations regarding signature authority and handling of unsolicited i
information have already been addressed in revisions to applicable NRR Office Letters. The team's report is under consideration by NRR management and plans L
to address the remaining recommendations are being developed.
At the direction of Chairman Jackson, the NRC staff performed an Independent Safety Assessment-(ISA) of MYAPCo during July and August of 1996. Chairman Jackson issued a report documenting the ISA team's findings on October 7.
l 1996. By memorandum dated November 27, 1996, the Executive Director for Operations (EDO) directed the staff to develop plans to resolve generic and plant-specific issues raised in the ISA report. These issues include the adequacy of the staff's analytic code review and power uprate review l
processes. The recomendations of the Maine Yankee lessons learned team in these areas will be considered in the development of NRR's plans to resolve the related ISA issues. NRR will develop a written sumary of the plan and l
schedule for the eight ISA issues for which NRR has been assigned lead responsibility. The staff's plans and schedules to address all of the recommendations in Attachment I will also be included in the sunmary schedule.
The sumary schedule will consider the resources needed to appropriately address the team's recomendations consistent with their 3riority in relation to other ongoing staff activities. As requested in the ED0's memorandum of November 27. 1996, the sumary should be provided to the ED0 in late February l
1997. This sumary will be provided to the Comission after review by the EDO and coordination of the resource implication with the CFO.
Coordination Statement The Office of the General Counsel has reviewed this paper and has no legal objection.
O.
SUMMARY
The Maine Yankee lessons learned team reviewed the staff's processes pertaining-to the review of code applications and power uprates, closeout of TMI Action Plan items, and the role and responsibilities of the NRR project manager. These issues were also raised in the OIG report. No immediate safety concerns were identified. Several recommendations were made for l
improving the staf f's processes. Some of the recommendations have alreaay t
been incorporated into NRR Office Letters. Details of the implementation of the remaining recommendations are being developed. The team's report is l
currently under management review to determine the appropriate scope, resources and priority for following up on these recommendations. A summary of the staff's plan should be provided to the Commission in late March 1997.
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A g Executi r tor r Operations
Attachment:
1.
Re) ort of the Maine Yankee
_essons Learned Task Group i
DISTRIBUTION:
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UNITED STATES j
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NUCLEAR REr,L/J" N/ COMMl",310N o
e WASHINGTON, D.C. 20565-0001 Decater 5,1996 l
l MEMORANDUM T0: Gary M. Holahan, Director Division of Systems Safety and Analysis, NRR John A. Zwolinski, Deputy Director Division of Reactor Projects - I/II, NRR FROM:
Phillip C. Cota, Technical Assistant
- C#
Division of Systems Safety and Analysis, NRR Amy E. Cubbage, Reactor Systems Engine g[
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Reactor Systems Branch Division of Systems Safety and Analysis, NRR' Daniel H. Dorman, Project Manager d) w Project Directorate I-3 Division of Reactor Projects - I/II, NRR
SUBJECT:
REPORT OF THE MAINE YANKEE LESSONS LEARNED TASK GROUP In a January 5, 1996, memorandum, Ashok Thadani, Associate Director for Technical Review, requested that the Division of Systems Safety and Analysis (DSSA) address staff process issues related to the recent Maine Yankee experience involving the use of certain analytical computer codes. Following a preliminary assessment of the issues, it became clear that both the technic'al staff and the NRR projects organization needed to be involved in the development of lessons to be learned and that the issues affect all NRR technical review activities.
In an April 25, 1996, metorandum, Gary Holahan described the formation of a task group of 14RR technical and projects staff to address these issues and to develop recommendations. The task group (consisting of Phillip Cota, Amy Cubbage, and Daniel Dorman, with support from Ralph Caruso of DSSA and Scientech, Inc.) has completed its work. Our report is attached.
Attachment:
As stated cc (w/ attachment):
W. McDowell, OIG P. Boenert, ACRS staff (15) i i
\\
REPORT OF THE MAINE YANKEE LESSONS LEARNED TASK GROUP Issued: December 1996 Task Group:
Phillip Cota, NRR/DSSA Amy Cubbage, NRR/DSSA/SRXB Daniel Dorman, NRR/DRPE/PDI-3 Contributors:
Ralph Caruso, NRR/DSSA/SASG Scientech, Inc., under contract No. NRC-03-95-026
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Table of Contents
[
East EXECUTIVE
SUMMARY
I 1
INTRODUCTION..........................................................
3 1.1 H i s t o r i c al B a c kg round............................................
3 1.2 Maine Yankee Lessons Learned Study and other Mai ne-Yankee-Rel ated Activi ti e s..................................
5 2 CODE REVIEW PROCESS...................................................
7 2.1 NRC Review and Approval of. ECCS Nethodol ogies.....................
7 2.1.1 Background................................................
7 2.1.1.
Examination of NRC Review and Approval of ECCS Methodologies.............................................
11 2.7.3 Recommendations for NRC Code Review Process...............
13 2.2 Followup on Licensee / Vendor Implementation.......................
13 2.2.)
Core Performance Action Plan..............................
13 2.2.2 Core Operating Limits Reports.............................
15 2.2.3 Recommendations for Followup on Licensee / Vendor Implementation............................................
15 2.3 C at al og ue o f C ode s...............................................
15 2.3.1' Discussion................................................
15 i
2.3.2 Recommendation............................................
16 3 POWER UPRATE REVIEW PROCESS...........................................
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3.1 GE BWR Power Uprate Program......................................
18 3.2 Other Completed Power Uprates....................................
21 3.3 GE BWR Extended Power Uprate Program.............................
26 3.4 Conclusions...................................................... 27 3.5 Recommendations................................................. 29 4 ISSUE CLOSURE AND INTERFACE ISSUES.................................... 31 4.1 Cl o s eout o f THI Acti on Items..................................... 31 4.1.1 Closeout Issues........................................... 31 4.1.2 Followup / Verification Process............................. 36 4.1.3 Recommendations........................................... 36 4.2 Staff Interfaces................................................. 37 4.2.1 Documentation of Communications with Licensees............ 37 4.2.2 Technical Staff Coordination and Concurrences............. 38 4.2.3 Signature Authority....................................... 39 4.2.4 Tracking Licensee Commitments............................. 41 4.2.5 Recommendations...........................................
41 LIST OF ABBREVIATIONS.................................................... 43 l
APPENDIX Plan to Address Lessons Learned from Maine Yankee Experience I
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l EXECUTIVE SLN9tARY j
In December 1995, the staff received allegations that the licensee for Maine Yankee Atomic Power Station had knowingly performed inadequate analyses of the emergency core cooling system (ECCS) and the containment in support of two power uprate amendments. The fact that the conditions asserted in these j
allegations were not identified by the NRC staff implies possible significant j
weaknesses in the NRC review and approval processes used in the subject power j
uprates.
(These allegations also implied significant deficiencies in the licensee's performance that the NRC staff is addressing separately from this t
activity.)
)
As a result of the allegations and: a subsequent assessment by the NRC staff, the Office of Nuclear Reactor Regulation's (NRR) Associate Director for l
Technical Review (ADT), in a memorandum dated January 5,1996, requested that t
the Director of NRR's Division of Systems Safety and Analysis (DSSA) address issues arising from the Maine Yankee experience.
In response to ADT's i
request, the Maine Yankee Lessons Learned Task Group (the team) was formed, j
and in a memorandum dated April 25, 1996, the Director of DSSA pr vided a plan i
for addressing the issues. This report presents the results of that effort.
Review and Followun of Analytical Codes and Methodoloaies The NRC staff determined that plant-specific application of RELAF5YA for Maine Yankee did not fully conform to the requirements of 10 CFR 50.46 and 10 CFR 50 Appendix K, nor had it been applied in a manner conforming to the conditions i
specified in the staff's SER, as necessary for NRC acceptance of the use of l
RELAP5YA for small-break loss-of-coolant accident (S8LOCA) analyses for Maine Yankee. As a result, the staff concluded that the S8LOCA portion of the ECCS j
analyses performed for Maine Yankee Cycle 15 did not conform to the j
requirements of 10 CFR 50.46.
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The team performed an assessment of the code review process, the' code i
modification process, and staff followup of vendor and licensee code i
implementation. Options for a catalogue of codes were evaluated. The assessment indicated a need for improved consistency and uniformity in the submittal and more formal staff guidance in the review of code applications.
j In addition, staff verification of licensee and vendor implementation should l
be improved.
j Power Vorate Review Process The allegations on Maine Yankee included the assertion'that inadequate i
analyses were performed by YAEC to support two power uprates (license l
amendments to increase the plant's licensed maximum reactor power level) for Maine Yankee. This assertion implies that the staff's reviews of the Maine Yankee power uprate applications were inadequate. To assess the adequacy of f
the staff's power uprate review process, the team examined past power uprate j
reviews and assessed them against current practice.
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The wide variation in the scope and depth of the completed power uprate reviews shows the need for standardization of license amendment application reviews and integration of technical review conclusions into licensing and licensing basis documents.
In addition, although the team did not identify any immediate safety concerns, the uprate reviews that have been conducted warrant a revisit to confirm the general conclusions of the reviews.
Closecut of TMI Action Items A document search was conducted to locate and compile the closeout documentation for TMI Action Plan Items II.K.3.5, II.K.3.30, and II.K.3.31 for all plants currently holding an operating license. Documents were examined to develop a general understanding of the review process applied to each item by the staff and to identify potential problem areas in the closecut.
Specifically, technical staff involvement in the closecut of each item for each affected plant was assessed, along with management oversight of the closeout documents and safety evaluations in the closecuts.
Further inspection of licensee and vendor implementation of S8LOCA evaluation models is recommended. Also, for several facilities, the team recommends staff
. verification of the applicability of the generic ECCS evaluation model.
Staff Interfaces The team assessed various staff guidance documents, including Management Directives, NRR Office Letters, and the Project Manager's Handbook (NUREG/BR-0073, Revision 1), for guidance regarding documentation of communications with licensees, technical. staff involvement, signature authority,. and tracking of licensee commitments.
In addition to evaluating the adequacy of staff guidance documents, current staff perfomance was benchmarked by reviewing selected documents generated by the projects organization within NRR during the first half of calendar year (CY) 1996. The documents reviewed. included a broad sampling of licensing action approvals and denials, and generic issue evaluations. The review indicated that management attention is needed to improve unifomity and consistency in the licensing review and follow-up verification processes. Communication of expectations regarding documentation of informal communications with licensees is also needed.
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1.
INTRODUCTION l
l On December 4,1995, the NRC received anonymous allegations regarding the Maine Yankee Atomic Power Station (Maine Yankee).
It was alleged that Yankee Atomic Electric Company (YAEC), acting as agent for Maine Yankee Atomic Power Company.(NYAPCo), the licensee for Maine Yankee, knowingly performed l
inadequate analyses of the emergency core cooling system (ECCS) and the containment to support applications for increases in the licensed maximum l
reactor power level.
When the NRC received the allegations, Maine Yankee had been shut down for i
refueling and steam generator repairs since February 6, 1995.
In response to i
the technical issues raised by the allegations, the NRC senc an assessment team to VAEC headquarters in December 1995 to review and assess YAEC's small-i break loss-of-coolant accident (58LOCA) and containment peak-pressure analyses related to the power uprate amendments for Maine Yankee. On the basis of this assessment and information obtained during a subsequent meeting on December i
18, 1995, the NRC issued on January 3,1996, an order. specifying requirements for reactor startup and limiting power to 2440 Wt. The order also specified requirements to be satisfied prior' to an increase in power to the previously l
approved limit of 2700 MWt.
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1.1 Historical Backaround l
MYAPCo was originally granted a license to operate Maine Yankee at a power of i
2440 Wt, based in part on a Combustion Engineering (CE) analysis of the ECCS.
4 By application dated August 1,1977, the licensee requested a single step increase in the maximum thermal power rating to 2630 Wt, based on the same CE l
ECCS model. On May 10, 1978, the NRC issued license amendment No. 38, which increased the licensed power level to 2630 Mt, but restricted operation to 2560 MWt until the Advisory Committee on Reactor Safeguards (ACRS) reviewed i
the power increase from 2560 to 2630 M t.
The power level of 2560 Wt is the l
level assumed in the Final Safety Analysis Report (FSAR) that supported the i
application for the operating license for Maine Yankee. On June 20, 1978, the l
NRC issued license amendment No. 39, which authorized the licensee to operate the plant at 2630 MWt.
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On December 28, 1988, the licensee submitted a request to amend the license to increase the plant's maximum thermal power rating to 2700 Wt, again based on the same CE ECCS model. The NRC granted this amendment request on July 10, i
1989, with license amendment No. 113.
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Licensees are required by 10 CFR 50.46 to demonstrate that the ECCS would protect the core during a loss-of-coolant accident (LOCA). The ECCS cooling i
performance must be calculated for several postulated LOCAs of different sizes and cher properties to provide assurance that the most severe postulated i
LOCAs are calculated. The regulation requires that the demonstration be i
performed using an acceptable evaluation model and allows two options: a i
conservative model meeting the criteria in Appendix K to Part 50, or a realistic model with an estimate of the uncertainty in the calculation. The second option was added in the 1988 amendment to the regulation because j
research has shown that Appendix K models are highly conservative.
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l Item II.K.3.30 of NUREG-0737, " Clarification of TMI Action Plan Requirements,"
which was issued in 1980, reflected a staff concern, in the wake of the TMI-2 accident, that a SBLOCA might be the most severe LOCA. This item called for licensees to eithur show that their current analyses were acceptable in light of the new concerns or submit for NRC approval revised SBLOCA models consistent with the requirements of Appendix K.
The revised models were to account for comparisons with experimental data, including data from the LOFT and Semiscale facilities.
Item II.K.3.31 stated that plant-specific small-break LOCA calculations, using models approved by the NRC under item II.K.3.30, should be submitted for NRC approval by all licensees to show compliance with 10 CFR 50.46, and that the calculations should be submitted within one year after staff approval of the LOCA analysis models.
In response to item II.K.3.30, YAEC submitted topical report YAEC-1300P, l
"RELAP5YA: A Computer Program for Light Water Reactor System Thermal-l Hydraulic Analysis" dated October 1982. By letter dated October 14, 1988, the NRC forwarded its safety evaluation report (SER) on RELAP5YA to YAEC and found the topical report to be acceptable for referencing in licensing applications, l
under the conditions specified in the SER. By letter dated January 17, 1989, to MYAPCo, the NRC approved the application of RELAP5YA to Maine Yankee under the conditions specified in the staff's SER.
Item II.K.3.5 requested PWR licensees to study the need for automatic trip of reactor coolant pumps during LOCAs. Generic Letter 83-10, " Resolution of TMI Action Item II.K.3.5, Automatic Trip of Reactor Coolant Pumps," requested licensees to justify use of manual action to trip the reactor coolant pumps i
for SBLOCAs.
In its reply dated June 28, 1985, the Maine Yankee licensee concluded that manually tripping the reactor coolant pumps was sufficient to l
satisfy the generic letter and 10 CFR 50.46. By letter dated April 15, 1986, the NRC accepted the licensee's position, which was based on analyses performed with RELAPSYA.
l Item II.K.3.31 was closed for Maine Yankee by a letter to MYAPCo from the NRC i
i project manager for Maine Yankee, dated May 8, 1989. The full text of the j
l letter follows.
"By telecon May 5,1989, Mr. S. Nichols of Maine Yankee informed me that your I
l computer model and program you developed concerning Small Break LOCA analysis per NUREG-0737 II.K.3.30 and II.K.3.31 is operational and will be used to develop your next fuel reload (Cycle 12).
Since this constitutes implementation, this closes ites II.K.3.31.
Item II.K.3.30 was closed by letter dated January 30, 1989. Thus, this completes NRC review of your Small Break LOCA analysis. Your computer program, its verification and implementation may, in the future, be the subject of an inspection by NRC."
However, NYAPCo did not use RELAP5YA to develop Maine Yankee's Cycle 12 fuel reload. The application of RELAP5YA to Maine Yankee was not accomplished until 1993, well into Cycle 13, and was not submitted to the NRC for review.
l Furthermors, the approach that was used in the analysis was not consistent 4
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j-with the conditions stated in the staff's approval for RELAP5YA. Thus the licensee's analysis did noc conform to the guidance in Item II.K.3.31.
i 1.2 Maine Yankee Lessons Learned Study and other Maine-Yankee-Related j
Activities As a result of the allegations and the subsequent assessment by the NRC staff, i
the' Office of Nuclear Reactor Regulation's (NRR) Associate Director for i
i Technical Review (ADT), in a memorandum dated January 5,1996, requested that
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the Director of NRR's Division of Systems Safety and Analysis (DSSA) address j
issues arising from the Maine Yankee experience.
In response to ADT's i
request, the Maine Yankee Lessons Learned Task Group was formed, and in a i
memorandum dated April 25, 1996, the Director of DSSA provided a plan for addressing the issues.
(The plan is included-in this report as an appendix.)
I, This report presents the results of that effort.
Other activities related to the Maine Yankee allegations were initiated in j
parallel with the Maine Yankee lessons-learned activity.
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The Office of the Inspector General (0!G) has conducted an event inquiry into i
the NRC staff's actions related to regulation at Maine Yankee. On May 8, 1996, OIG provided its report on the event inquiry to the Commission.
In the j
report, OIG arrived at the following nine conclusions:-
- 1. That although the NRR staff reviewed the RELAP5YA computer code method, 1
-there was weakness in the review process.
"OIG found that NRR reviewed the RELAP5YA code for Maine Yankee independent of the code plant specific i
application. Normally the codes and plant specific applications were reviewed together, but not so with the RELAP5YA code for Maine Yankee."
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- 2. That the NRR staff was unaware of MYAPCo's non-compliance with five of the s
SER conditions until December 1995.
"0!G found that the NRR staff did not follow-up on the SER with MYAPCo after the SER was issued in January 1989."
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- 3. That the close-out of TMI Item II.K.3.31 by the NRC staff was i
inappropriate.
"With respect to'NRC's May 8,1989, letter that closed out i
TMI Item II.K.3.31, OIG determined the following: the former Project 1
Manager, the author of letter, did not follow the established practice of procedure of obtaining NRR technict.1 staff review; the former Project Manager did not follow the established concurrence format of the PDI-3; the j
former Project Manager apparently made a unilateral decision regarding the closure of TMI Item II.K.3.31; and the former Project Manager was vague and j
made the close out letter subject to misinterpretation."
- 4. That there was a lack of NRR management oversight regarding the May 1989 p
letter.
"0IG found that the NRR staff listed for distribution of the May letter had the opportunity to question the letter. OIG disclosed that none i
of the NRR staff listed for distribution questioned the letter or the close i
i out of TMI Item II.K.3.31."
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- 5. That the closecut of TMI Item II.K.3.31 was overlooked by the staff.
"0IG 3
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learned that a review of the TMI Items status was conducted by NRR during i
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1989. The inquiry found that the NRR Project Managers, technical staff l
managers and senior officials had several opportunities to identify and l.
resolve the erroneous closure of TMI Item II.K.3.31."
- 6. That the NRR Project Managers had several conversations with the licensee in which the licensee made commitments with respect to the 58LOCA analysis.
i "0!G found that the NRR Project Managers did not follow-up on the licensee's commitments."
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- 7. That NRR staff did not have and presently does not have a farmal licensing commitment tracking system.
"0IG determined that the lack of a formal i
licensing commitment tracking system was a contributing factor to the NRC being unaware of MYAPCo's non-compliance with the SER and TMI Ites l
II.K.3.31."
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- 8. That NRR did not have a policy on Project Managers documenting and l
retaining their documentation of conversations with licensees.
"One former Project Manager stated to OIG that he had a policy of not taking notes and j
if he did take notes, he would later destroy them. Another former Project Manager stated to OIG that any documentation of past conversations with the l
licensee would not have been retained by him. O!G found that the Project i
Managers' lack of documentation has placed the agency in a position of having to rely on the licensee's documentation when inquiring into past events."
- g. That "the these of NRR's reliance on the licensee resounded throughout this
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investigation. OIG revealed several examples where the NRR staff relied on MYAPCo to follow. the NRC requirements and regulations, however, NYAPCo did not adhere to NRC requirements and regulations."
In a memorandum dated May 24, 1996, to the Executive Director for Operations (ED0), the Chairman requested the staff's plans to address the findings of the report.
In a Commission paper dated June 21, 1996 (SECY-96-135), the EDO l
provided the staff's plans and stated that the staff would report the results and status of corrective actions taken and planned to the Commission by November 1996. Some of the issues raised by the OIG report were addressed in the Maine Yankee Lessons Learned Task Group plan.
i The OIG report also found that MYAPCo did not report modifications to RELAP5YA i
and problems experienced with the code as required under 10 CFR 50.46, and found that the licensee did not use RELAP5YA in accordance with its SER and j
1MI Action Item II.K.3.31.
In response to the OIG findings, and to respond to concerns by the Governor of Maine about the safety and the effectiveness of i
regulatory oversight of Maine Yankee, the Chairman initiated an independent safety assessment of Maine Yankee. The purpose of the independent safety assessment at Maine Yankee was to evaluate (1) the conformance of the plant to 9
its design and licensing bases, (2) licensee self-assessments, corrective i
actions and improvement plans, (3) the root cause(s) of significant deficiencies, and (4) operational and overall plant safety performance. The
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report of the independent safety assessment was issued in October 1996.
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4 2.
CODE REVIEW PROCESS It was determined that RELAP5YA was not applied for Maine Yankee in a manner conforming to the requirements of 10 CFR 50.46 and 10 CFR 50 Appendix K, nor had it been applied in a manner conforming to the conditions specified in the staff's SER, as necessary for NRC acceptance of the use of EELAP5YA for SBLOCA j
' analyses for Maine Yankee. As a result, the staff issued an Order and Demand for Information restricting power.to 2440 megawatts-thermal (MWt). This issue led to the formation of the Maine Yankee Lessons Learned Task Group to perform a self assessment of the code review process, the code modification process, staff followup of vendor and licensee code implementation, and to evaluate 4
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options for a catalogue of codes. The team has completed its assessment in these areas and the results and recommendations from this as m ssment are 3
provided in the following discussion.
l 2.1 NRC Review and Anoroval of ECCS Methodoloaies
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Background===
j 2.1.1 j
The review and approval process for an ECCS evaluation methodology is a complex technical effort, which can take a very long time to complete. The review process developed following lengthy hearings conducted in the early 1970's, and has evolved over the years.
In order to put the information i
presented in later sections in context, a discussion of ECCS analysis i
methodologies, regulatory requirements, and the regulatory review process as i
it applies to ECCS evaluation models is provided below.
I 2.1.1.1 Staff-Approved ECCS Methodologies i
While many licensees have developed their own in-house transient analysis i
capability,'ECCS evaluation models have been almost exclusively developed by i
nuclear steam supply system (NSSS) and nuclear fuel vendors. The first evaluation models subject to extensive regulatory review were those developed under the 1971 interim acceptance criteria for ECCS evaluation models. These were large-break loss-of-coolant-accident (LBLOCA) methods developed by the l
four domestic NSSS vendors: Westinghouse (M), General Electric (GE),
f Combustion Engineering (CE), and Babcock and Wilcox (B&W). The LBLOCA was designated as the design basis accident, which determined the performance i
requirements of the ECCS. Under the design basis accident concept, the LBLOCA was the most limiting credible event. A system designed to mitigate this event was believed to be able to handle all other, less limiting events.
1 Hence, it was thought that only this event needed to be considered.
In i
conjunction with the design basis accident (DBA) concept, 10 CFR 50 Appendix K i
was developed to specify attributes of acceptable LBLOCA evaluation models (ems), and 10 CFR 50.46 was incorporated to specify the acceptance criteria for ECCS based on analyses conducted using Appendix K codes. These criteria, which were promulgated in January of 1974, are applicable to all light water reactors which use zirconium fuel cladding.
Each of the NSSS vendors a
i submitted LBLOCA models for regulatory approval to comply with the final I
acceptance criteria.
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1 For pressurized water reactors (PWRs), it was realized even before the final acceptance criteria were issued, that some of the required and acceptable features of ECCS evaluation models specified in Appendix K (notably those related to ECCS bypass and reflood) were not applicable for small breaks.
Therefore, the PWR NSSS vendors developed and submitted separate models for analysis of SBLOCAs. For boiling water reactors (BWRs), there is significantly less change in phenomenology as break size decreases, so separate models have not been developed. Another reason is that BWRs have an automatic depressurization system (ADS), which opens valves to depressurize the reactor coolant system under accident conditions, allowing full ECCS flow to mitigate the accident consequences.
Following issuance of the final acceptance criteria, Exxon Nuclear Company, a supplier of both BWR and PWR fuel,' developed ECCS methodologies for both types of plants. Exxon Nuclear later changed its name to Advanced Nuclear Fuels Corporation, and subsequently was acquired by and merged into Siemens Power Corporation. Within the last year, ABB-CE has obtained regulatory approval for a BWR ECCS methodology. This ECCS methodology development was initiated by Westinghouse and Asea Brown Boveri (ABB) in an attempt to enter the domestic BWR fuel market, and was completed by ABB-CE following ABB's acquisition of Combustion Engineering.
The Babcock and Wilcox Company has recently been acquired by Framatome and has changed its name to Framatome Technologies, Inc. (FTI). The FTI NSSS has a once through steam generator (OTSG) design, which differs from the U-tube steam generators used in Westinghouse and ABB-CE plants. The OTSG plants also have vent valves between the outlet plenum and the downconer, which significantly changes many aspects of LOCA phenomenology. Therefore, a separate methodology is necessary to handle the OTSG plants. The original ECCS method developed by B&W applied only for OTSG plants. When B&W began refueling U-tube plants, it was necessary to develop a separate methodology.
Therefore, FTI now has separate methods for OTSG and U-tube steam genuator plants.
Table 1 summarizes approved ECCS models de eloped by NSSS and fuel vendors.
Table 1.
Summary of NSSS and Fuel Vendor ECCS Methodologies VEND 0R METHODOLOGY (C0 DES)
Westinghouse Electric Corp.
PWR LBLOCA (BART, BASH, SATAN, etc.)
Westinghouse Electric Corp.
PWR SBl.0CA (NOTRUMP)
General Electric Co.
General Electric Co.
ABB-Combustion Engineering PWR LBLOCA (CEFLASH-4A, etc.)
ABB-Combustion Engineering PWR SBLOCA (FLASH-4AS, etc.)
8
l i
l ABB-Combustion Engineering BWR LOCA (GOBLIN, etc.)
{
Framatome Technologies, Inc.
OTSG PWR LBLOCA (CRAFT 2, etc.)
j Framatome Technologies, Inc.
OTSG PWR SBLOCA (CRAFT 2, etc.)
Framatome Technologies, Inc.
RSG PWR LBLOCA (RELAP5/M002, etc.)
Framatome Technologies, Inc.
RSG PWR SBLOCA (RELAP5/M002, etc.)
I Siemens Power Corp.
PWR LBLOCA (RELAP4-EM,-T000EE2, etc.)
l Siemens Power Corp.
PWR SBLOCA (ANF-RELAP, T000EE2, etc.)
l Siemens Power Corp.
BWR LOCA-(RELAP4/ ENC-288, etc.)
4 1
Some utilities have developed or attempted to develop their own in-house LOCA
}
methods.
In addition to YAEC, which has approved LOCA methodologies for PWRs and BWRs, the only other utility which has an approved LOCA methodology is Northeast Utilities, which has an approved PWR SBLOCA method for the Haddam Neck Plant. Other utilities have taken the approach of performing their own i
LOCA analysis by using methodologies already developed by a vendor. Utilities i
performing their own ECCS analyses using vendor methods include Virginia Power, which uses Westinghouse methods, and Texas Utilities, which uses Siemens methods. Texas Utilities submitted Topical Reports which document the i
application of Siemens methods to Comanche Peak for SBLOCA and LBLOCA. The i
Northeast Utilities, YAEC, FTI, and Siemens methodologies are all based in j
part on versions of the RELAP code, which is an NRC-developed code.
2.1.1.2 ECCS Methodologies ECCS methodologies are based on one or more computer codes, which are used.in 1
parallel or in sequence to simulate the complete LOCA event. The number of codes used varies among the vendors and also varies for the type of event.
1 Early PWR methods tended to use separate codes for the blowdown portion and 1
the reflood portion of the event, and also to use a separate code for the fuel i
heatup or hot channel analysis. Separate codes are generally also used to determine the fuel temperature initial conditions and the containment i
response. These codes were not examined in detail for this report. Vendors may include a description of the fuel performance and containment codes along with the base methodology.
If such descriptions are not included, than j
separate Topical Reports are submitted to describe these codes.
I i-The process of obtaining regulatory approval for an ECCS evaluation generally requires three steps. First, topical reports describing the computer codes to be used are submitted for approval. These reports may include benchmarking of the codes against relevant experimental data. Then a second topical report is 4
i submitted describing the ECCS analysis methodology. This so-called i
" Applications Report" describes how the computer codes will be used together to perform the complete ECCS evaluation. Sample calculations are usually included to illustrate the application. Finally, plant specific analyses, or 1
analyses specific to groups of plants with similar designs (plant class a
i 9
2
specific), are performed and documented in a third report, the licensing analysis. This report actually determines the limiting conditions for operation-(LCOs) that result from the LOCA analysis.
Utilities performing their own analyses using an approved vendor method have submitted only the licensing analysis report, which may contain some aspects of the applications report, e.g., a noding study for the plant specific application.
2.1.1.3 ECCS Model Revisions and Replacements For various reasons, NSSS and fuel vendors have occasionally updated their ECCS models, either making revisions to the codes and/or methodology to improve model accuracy, or developing a completely new methodology based on different computer codes.
10 CFR 50.46 allows changes to or corrections in existing models without prior NRC approval. Such changes must be reported to the staff at least annually. External factors have sometimes influenced the updating and development of revised ECCS models. Three factors which influenced revisions or new ECCS models are:
- 1. NUREG-0737, Post TMI Action Items, in particular item II.K.3.30, justification of SBLOCA methods.
- 2. SECY-83-472', which provided an alternative ECCS analysis approach for performing LBLOCA analyses in conformance with 10 CFR 50 Appendix K.
The paper also included a discussion of the basis for the revision to 10 CFR 50.46 which allowed realistic analyses.
- 3. Revision of 10 CFR 50.46 to allow realistic LOCA analysis.
Following the TMI accident, the NRC requested each licensee to justify the SBLOCA' methods applied to its plant. NUREG-0737, in particular item II.K.3.30, resulted in some of the SBLOCA methodologies being revised, and/or additional justification being submitted to demonstrate conservatism.
Extensive confirmatory research conducted by the NRC in conjunction with industry on ECCS performance (e.g., LOFT, Semiscale, FLECHT, and MIST) and associated NRC code development (RELAP, TRAC, etc.) demonstrated that the evaluation models for LBLOCA were conservative and embodied considerable margin in terms of the predicted peak clad temperature (PCT). Some relief, within the then-current Appendix K, was granted by SECY-83-472. This prompted revisions of LOCA models. Some of these revisions demonstrated additional margin in the ECCS and were used to justify power uprate requests.
Regulations were promulgated in 1988 in revisions to 10 CFR 50.46, allowing for realistic LOCA analysis. Statistical uncertainty evaluation was required to quantify margins. This relief was optional, in the sense that continued use of the old Appendix K models was permitted, subject to some restrictions on specific models-(e.g., Dougall-Rohsenow post-CHF heat transfer).
Regulatory Guide 1.157, dated May 1989, was issued to provide guidance for realistic calculations of ECCS performance. Only one methodology has been approved under these provisions, Westinghouse realistic LBLOCA using MCOBRA-10
i i
i t
TRAC. Combustion Engineering, Siemens, and General Electric have developed realistic methodologies which have not yet been reviewed or approved by the NRC. The WCOBRA-TRAC methodology was the subject of extensive regulatory review, including lengthy review by the Advisory Committee on Reactor j-Safeguards (ACRS).
j 2.1.? Examination of NRC Review and Approval of ECCS Nethodologies
]
I l
The Naine Yankee lessons learned task group, with the assistance of its l
contractor, Scientech, Inc., has examined previous NRC reviews leading to the j
acceptance of several ECCS evaluation models and model revisions to assess the review process. These include the 14 NSSS and fuel vendor methodologies listed in Table 1.
Also examined were YAEC's LOCA methodologies, the SBLOCA methodology developed by Northeast' Utilities for the Haddam Neck Plant, and the application of the Siemens small break and L8LOCA methodologies by Texas Utilities Electric for the Comanche Peak plants.
The examination covered all available documentation of the reviews, including submittals, staff requests for additional information (RAIs), responses to RAls, meeting summaries, and staff SERs, which were gathered from both publicly available and internal NRC document archives. The information extracted from the documents includes: computer codes which are used for the analyses, number and description of sensitivity cases, number and description of benchmark cases, sample applications, number and level of detail of the RAls, meetings held including presentation to the ACRS, number and content of conditions imposed in the staff SERs, and availability of verification of the implementation of the SER conditions.
2.1.2.1 Results of Examination Difficulties were encountered in retrieving some of the documentation of staff reviews of ECCS methodologies. The amount of infomation that could be retrieved was strongly dependent on the time frame in which the review was performed. Many of the reviews were initiated and/or completed before the NRC's document retrieval system, NUDOCS, was developed. For more recent reviews, documer.tation was readily available.
A great diversity in the content and organization of the ECCS methodology documentation was evident in this examination. Unlike the FSAR, there is no format and content guide for code and methodology topical reports.
Each vendor or licensee exhibits individual style, organization, and content.
In general, there are three types of topical reports associated with ECCS methodologies. The first type describes one or more of the computer codes used to perform the analyses. The second type describes the methodology and is called the applications report. The third type documents the plant or plant class specific analysis. However, the documentation examined shows that there are many exceptions to this format and a wide variation in terms of the breakdown of information between the various types of topical reports. One of the vendors has made a practice of including the SERs for previous revisions of their topical reports in their submittals. This was found to be helpful in reconstructing the review process for their methodologies.
p 11
1 NUREG-0390, " Topical Report Review Status," which is published semiannually, provides industry with procedures for submitting topical reports; guidance on how the NRC processes and responds to topical report submittals; and an accounting, with review schedules, of all topical reports currently accepted for review by the NRC. Beginning in 1984, the NUREG guidance includes procedures for publication of approved versions of reports. The current guidance states that, after the NRC accepts a licensing topical report for referencing, the sponsoring organization should publish an approved version and that a copy of NRC's transmittal letter and its evaluation report should be inserted immediately after the title page of the approved version.
In early documentation (prior to the mid 1980's), considerable difficulty was encountered in locating approved versions of the topical reports, i.e. with the SER included.
For most of the methodologies examined, the team was able to retrieve the RAls f
and responses to RAIs. The RAIs were numerous and detailed, indicating an adequate scope and depth of review. Among the documentation examined, there was wide variation in whether and how RAI responses were included in the j
approved versions of the topical reports. Documentation of the RAI responses
)
was included as appendices, separately bound supplements, in a separate i
licensing documents volume, or not inc1cded at all.
Early period documentation often does not include the RAI responses. NUREG-0390 does not provide guidance with regard to including RAls and responses to RAIs in the i
approved versions of topical reports.
In addition to the recent problems with the RELAP5YA code, inadequacies have been discovered in the Siemens LBLOCA model. Sample applications were not provided at the time of review of either of these methodologies, which may have contributed to the problems that have been' encountered with these methodologies. Sample applications were provided for all other ECCS methodologies examined. Benchmark cases were provided for all of the methodologies examined, and with the exception of one methodology for which documentation was limited, sensitivity cases were provided for all of the methodologies examined.
There was wide variation in the number and content of conditions or restrictions imposed in the staff's SERs. Most of the SERs contained some conditions or restrictions, and a few of the SERs contained 9 or more.
It was found for some of the topical reports that the conditions imposed in the staff's SER were not consistent with the conditions in the attached technical evaluation report (TER) prepared for the staff by a contractor. This inconsistency could cause confusion and potentially result in the improper implementation of the conditions. There was no information available in the documentation examined to indicate that the staff had verified vendor / licensee conformance to the restrictions and/or conditions in the staff's SERs.
Verification of conformance to SER conditions is discussed further in sections 2.2.2 and 2.2.3.
As a result of the Maine Yankee issue, the regulatory status, i.e.
enforceability, of conditions imposed in staff SERs has been called into question. Therefore, the technical staff has been instructed that conditions I
should no longer be imposed in staff SERs approving topical reports or 12 i
n
technical specification (TS) amendments. Alternatively, licensees and vendors must commit to any restrictions or conditions which must be satisfied for j
staff approval of topical reports or TS amendments. Any licensee or vendor i
commitments which are relied upon for staff conclusions will be specified in
}
the letter granting approval of topical reports or TS amendments and in the i
staff SER supporting approval.
It should be noted that recent guidance from i
the Office of General Counsel (OGC) emphasizes the lack of legal force of l
vendor and licensee commitments without imposition by order or incorporation into a license.
i ACRS involvement was evident in the reviews of about half of the ECCS methodologies examined.
i 2.1.3 Recommendations for NRC Code Rev'.ew Process l
Based on the team's review, the foll uing recommendations have been developed:
j (1) A standard format and content guide for topical reports documenting ECCS i
methodologies should be developed. The guide would provide assurance of j
uniformity and consistency in the level of documentation and validation that j
is provided.
l (2) The guidance of NUREG-0390 should be modified to specify that RAls and 3
responses to RA!s be included in the approved versions of topical reports to j
provide complete documentation of the staff's review.
i (3) sample app 1'ications of codes and methodologies should be required to be j
submitted for approval of codes and methodologies.
l l
(4) Conditions or restrictions should not be imposed in topical report safety evaluations without prior commitment by the vendor or licensse.. (Even with I
l i
prior vendor or licensee commitment, conditions and restrictions on topical report approvals should be minimized.)
i (5) Clear guidance should be provided to the staff regarding the regulatory j
status and enforceability of licensee and vendor commitments.
2.2 Followun on Licensee / Vendor Innlementation The Maine Yankee Lessons Learned Task Group was directed to review the results of completed audits and inspections in this area, to determine if the Core i
Perfomance Action Plan should be modified in light of its findings to include more emphasis in the area of licensee / vendor code implementation with an i
emphasis on how SER conditions are satisfied, and to determine if the guidance in Generic Letter 88-16, " Removal of Cycle-Specific Parameter Limits from i
Technical Specification," needs to be modified to be more specific with regard i
to SER conditions.
i
{
2.2.1 Core Performance Action Plan l
The Core Performance Action Plan was developed in 1994 to assess the impact of j
reload core design activities on plant safety. The action plan includes 13 4
s k
l t
several major task areas including the following, which are relevant to followup of code implementation:
(1) inspection of nuclear fuel vendors; (2) inspections of licensees' reload analyses; and (3) evaluation of inspection guidance.
Since 1994, the staff has completed five performance-based vendor inspections and four licensee reload analyses inspections. Through these inspection efforts, a total of 26 plant specific cycle reload analyses have been evaluated. The' scope of these inspections has included the reload analysis methods and computer code models. The bases for inspection of code implementation include 10 CFR 50 Appendix B and the appropriate American Nuclear Society (ANS) and Institute of Electrical and Electronics Engineers (IEEE) code documentation, validation, and verification standards. Compliance with applicable SER restrictions is also reviewed.
To more effectively evaluate licensee reload analysis capability, the scope of inspection activity was expanded for fiscal year 1997. The planned inspection activities will emphasize vendor and licensee interaction and oversight and will include: six licensee reload inspections (focus on in-house analyses),
four licensee / vendor interface specific inspections, four reactive or issue followup inspections, one direct vendor inspection, and four vendor lead test assembly program inspections.
The team has reviewed the results of completed inspections to determine the extent to which inspections have emphasized code implementation and conformance with the conditions of staff SERs. Areas of concern that have been identified by the Core Performance Action Plan include organizational interfaces, data transfer control quality assurance (QA), and potential weaknesses of oversight audit functions conducted by licensee technical staff.
While there has been significant emphasis in the completed inspections on reviewing the implementation of physics codes, core thermal-hydraulic codes, fuel performance codes, and non-LOCA transient and accident codes to perform reload core design and safety analyses, there has not been an emphasis in the area of implementation of ECCS evaluation methodologies, nor has it been documented in inspection reports that conformance with SER conditions has been verified for the codes that were reviewed.
While there is a clear regulatory requirement that ECCS analyses be performed using an NRC approved methodology (i.e.,10 CFR 50.46), the team noted that the regulatory basis for staff review and approval of other codes (e.g.,
physics codes, core thermal-hydraulic codes, fuel performance codes, and non-LOCA transient and accident' codes) used to perform reload core design and safety analyses is not clear. Historically, vendors and licensees have submitted such codes for NRC review and approval.
An inspection is planned for early 1997 at Siemens Power Corporation (SPC),
focusing in part on SPC's various analytical methodologies. This aspect of the inspection was motivated by problems identified in a reflood heat transfer correlation in SPC's LBLOCA evaluation model. The inspection will also emphasize other areas, which are typically covered by the Core Performance Action Plan inspections.
14
i i
l 2.2.2 ' Core Operating Limits Reports i
Generic Letter 88-16. " Removal of Cycle-Specific Parameter Limits from Technical Specifications," was issued to describe and provide guidance for the implementation of an alternative to specifying the values of cyc19-specific parameter limits in the TSs. This alternative approach, which has been adopted by most licensees, eliminates the majority of TS amendments associated L
with changes in the values of cycle-specific parameters in TSs. Under this approach, the TSs specify the methodologies that the licensee will use to i
calculate cycle-specific parameters. The actual values of the parameters are maintained in a core operating limits report (COLR).
4 l
While the guidance in Generic Letter 88-16 specifies that cycle-specific j
parameter limits should be calculated using NRC approved methodologies, it is silent with respect to assurance that SER conditions are satisfied for the methodologies that are used to calculate the cycle-specific parameter limits.
A sample of staff SERs for TS amendments for individual licensee conversions to the GL 88-16 approach were also examined and were silent with regard to conditions in the staff's SERs approving methodologies, but did note that all i
of the referenced methodologies had been previously reviewed and approved by l
the NRC.
l-l 2.2.3 Recommendations for Followup on Licensee / Vendor Implementation i
Based on the team's review, the following recommendations have been developed:
(1) Additional emphasis should be placed on audits and inspections of i
' implamentation of ECCS methodologies.
J l
(2) Additional' emphasis shoald be placed on verification of conformance to SER conditions in the area of inspections and audits.
j (3) The Core Performance Action Plan should be modified to incorporate recommendations 1 and 2 above.
l (4) The regulatory basis of staff review and approval of codes other than ECCS methodologies should be examined, and consideration should be given to revising the regulations to address this issue.
(5) Guidance should be provided to the staff to ensure that conformance to topical report SER conditions is verified whenever licensee or vendor application of codes or methodologies is under staff review, (e.g., plant specific applications of approved vendor methodologies, power uprate applications, TS amendments, and COLR conversions.)
I 2.3 Cataloaue of Codes 2.3.1 Discussion During its review of recent events involving the Maine Yankee SBLOCA analysis and other code related issues, the staff has found it necessary to identify I
and understand the review and approval process for a particular code or 15 i
3
i analysis, as well as the limits of its applicability.
In addition, the staff needs to know the status of codes when it is reviewing license amendment submittals that employ analytical codes. However, the staff does not currently maintain any coordinated list of the review and approval of analytical methods; therefore, the memory of staff members and the ability to retrieve documentation from the docket file or NUDOCS must be relied upon to answer subsequent questions about a particular model or method. Significant difficulties were encountered while obtaining documentation to support the examination of the LOCA code review process discussed in Section 2.1.2.1.
The staff response to code related events could be enhanced, and the potential for code errors and misapplications would be reduced, if the staff maintained a catalogue of analytical code reviews and approvals.
2.3.2 Recommendation A catalogue of codes should be developed and be updated continuously.
Its scope should at least include thermal-hydraulic codes, nuclear physics codes, nuclear fuels codes, fuel / mechanical codes, and post-LOCA containment performance codes.
A statement of work has been drafted which describes the act!ons that need to
)
be performed by a contractor to develop, install, and load the initial set of j
data into an NRR code catalogue. Initially, the planned scope of the catalogue will include thermal-hydraulic codes, nuclear physics codes, nuclear fuels codes, and fuel / mechanical codes, which are used to understand the performance of the reactor core and reactor coolant system during trarsients and accidents, and also post-LOCA containment performance codes. Optionally, the scope may be expanded to cover other codes such as structural analysis codes, radiological protection and shielding codes, mechanical engineering codes, and electrical system codes. The catalog would be updated by the NRC staff.
3.
POWER UPRATE REVIEW PROCESS The allegations on Maine Yankee included the assertion that inadequate analyses were performed by YAEC to support two power uprates (license amendments to increase the plant's licensed maximum reactor power level) for Maine Yankee. This assertion implies that the staff's reviews of the Ma %
l Yankee power uprate applications were inadequate. To understand the adequacy of the staff's power uprate review process, the Maine Yankee Lessons Learned Task Group, with the assistance of its contractor, Scientech, Inc., examined past power uprate reviews and assessed them against current procedures and practice.
On the basis of an inquiry to operating reactor project managers and a search of NUDOCS, thirty-one completed power uprates were identified. Some of these uprates had not required a new safety review by the staff, because the FSARs supporting the applications for operating licenses for the plants had been written assuming the' power levels to which the plants were later uprated, and the staff safety evaluations of these applications had been performed assuming these power levels. For each'of these early plants, the Commission had 16
i responded to the application for an operating license by granting a provisional operating license, which limited the thermal power output of the reactor until its performance could be further evaluated. Later, the Commission granted a full-term operating license at the requested power level.
Of the thirty-one completed power uprates identified, nine are in this category.
In each of these cases, the staff reviewers verified that all the analyses in the FSAR were performed at the power level requested in the uprate application, re-reviewed any re-analyses performed by the uprate applicant, and confirmed that the plant was now fully analyzed at the proposed power level and core loading.
The remaining twenty-two power uprate applications, which are listed in Table j
2 required supplementary reviews by the staff. These uprate reviews were
?
assessed by the team.
Table 2.
Power Uprates That Required Supplementary Reviews i
PLANT DATE j
Callaway 03/30/88 l
Calvert Cliffs 1 09/02/77 Calvert Cliffs 2 10/19/77 D.C. Cook 2 01/14/83 Fermi 2 09/09/92 Fort Calhoun 08/15/80
^
Hatch 08/31/95 Limerick 1 01/24/96 Limerick 2 02/16/95 Maine Yankee 05/10/78 Maine Yankee 07/10/89 Millstone 2 05/12/79 Nine Mile Point 2 04/28/95 North Anna 08/25/86 peach Bottom 2/3 10/18/94 St. Lucie 1 11/23/81 St. Lucie 2 03/01/85 Surry 08/03/95 Susquehanna 04/11/94 17
________.____________._____._.._.__.____y 1
l 1
i PLANT DATE f
{
Vogtle 03/22/93 E
t Wolf Creek 11/10/93 j
WNP-2 04/25/95 l
i In each case, the team reviewed the staff SER, the power uprate application, i
and the licensee responses to staff requests for additional informai. ion. Each l
power uprate review was assessed in light of the Maine Yankee allegations and the problems the staff found in its December 1995 assesgment of YAEC's SBLOCA and containment :;4ak-pressure analyses for Maine Yankee. The team looked i
for the followin'; attributes in the staff's review:.(1) Did the reviewer
~
determine whethu the analytical codes used to support the uprate application j
were the same as those which were approved and whether the codes were approved a
for use for the purpose to which they were being applied? (2) If the licensee j
was applying the code to the subject plant for the first time, did the i
reviewer confirm that the code was used in accordance with conditions in the SER that approved the code?. (3) Did the reviewer review all analyses beyond those that were approved? (4) Were technological developments and plant modifications that had occurred since approval of the analytical codes used by l
the applicant ap,,ropriately considered? (5) Did the reviewer establish the license conditions and technical specification changes needed for the license l
amendment? (6) Did the reviewer address what follow up is needed to verify
]
that uprate changes are incorporated into the updated final safety analysis l
report (UFSAR)?
In addition, the team compared the scope of the uprate reviews to identify j
differences in the safety topics considered in the reviews.
\\
l 3.1 GE BWR Power Vorate Proaram 1
The NRC does not have a standard procedure for reviewing power uprate j
applications, but the staff has taken a generic position on a GE program for e
uprating BWRs.
In December 1990, GE Nuclear Energy submitted a licensing j
topical report entitled " Generic Guidelines for General Electric Boiling Water l
Reactor. Power Uprate." The original proposal by GE did not limit the power i
increase that a licensee could request through the program. A June 1991 revision to the topical report contained proposed licensing criteria for l
review topics such as transient analyses, containment response, ECCS/LOCA response. and the set point methodologies for instrumentation and control; and a
In response to the allegations. received in December 1995, the NRC staff conducted an audit of the Maine Yankee SBLOCA and containee'nt peak-pressure analyses at the licensee's engineering services contractor. As a result of this review, the staff issued an Order and Demand for Ir. formation on January 3, 1996, restricting power to 2440 MWt and containment pressure to 2 psig.
18
+,,,
GE agreed to limit the maximum power increase to be made available under the program to approximately 5 percent of rated thermal power. An increase of this magnitude or less is called a " stretch power" increase, because the nuclear steam supply system was designed for this higher power level, although the vendor-guaranteed or " nameplate". rating of the reactor was the i
. power level considered in the FSAR.
In September 1991, the staff sent to GE Nuclear Energy the staff's position paper regarding the proposed generic power uprate program, and in December 1991, the staff sent the position paper to the Commission. The position paper affinned the staff's commitment to developing the program and included a conditional apprcval of GE's topical report.
In i
July 1991, GE Nuclear Energy submitted a licensing topical report entitled l
" Generic Evaluations of General Electric Bolling Water Reactor Power Uprate,"
which provided generic bounding analyses and equipment evaluations, and in July 1992, the staff sent to GE Nuclear Energy the staff's SER for the topical report. The staff found that the topical report, when combined with sufficient addW.onal plant-specific information, constitutes an adequate basis for the review of individual licensee power uprate requests. The staff position paper and the SER on GE's BWR power uprate generic analyses prescribe the scope, depth, methodology, criteria, and limitations of a BWR stretch power uprate review in the GE power uprate program, j
The lead plant for the GE BWR generic power uprate approach was Fermi 2.
The staff review satisfied some of the criteria identified earlier in this 1
section. The staff position paper on the proposed generic power uprate program addressed selection and approval status of codes used to support the uprate application, and the position paper placed two conditions on the proposed use of two new codes in the generic power uprate program.
l SAFER /GESTR (for ECCS analysis) is approved; if it is used, a baseline run at R
the present power level must be included so that the true effect of the power i
uprate can be assessed. SHEX (for calculation of suppression pool response to LOCA) is not approved for generic use; if used, use must be justified. These l
codes were used for Fermi 2, and the SER showed evidence that the conditions in the position paper were satisfied. The review also included consideration of technological developments and plant modifications that had occurred.
Design changes were reviewed, and the code used for SBLOCA analysis of the J
ECCS was in conformance with Item II.K.3.31 of the TMI Action Plan. The review also considered at least most changes needed in the plant's technical specifications, although some technical specification changes (e.g. changes to TS 3.8.4.3, which requires thermal' overload protection for MOVs) were not discussed in the SER. The ACRS conducted a limited review of the power uprate for Fermi 2.
The team did, however, find room for improvement in the Fermi 2 review with respect to the identified criteria:
- 1. The power uprate SER did not confirm that use of new (i.e., not previously approved for use at that plant) codes was in accordance with conditions in the SERs that approved the codes.
- 2. With a few exceptions, it was not clear from the uprate application or the SER which analyses were done with codes that were previously used and approved for that plant and which were not.
19
L l
i i
- 3. The'SER did not confirm that new codes used in the uprate analyses were i
identified in the proposed technical specifications.
1
- 4. The review did not consider changes. needed to the plant's updated final safety analysis' report (UFSAR). The licensee's application for power i
uprate was supported by much design analysis, which included the use of new analytical codes. The staff should ensure that this new information is i
incorporated into the UFSAR.
I Applications for construction permits and operating licenses are accompanied by safety analysis reports, so staff reviews of these i
applications need not be concerned with this problem. By referring to the-l FSAR for the plant, the license makes the FSAR part of the licensing basis.
i But a power uprate application is for a plant that already has a current plant safety analysis report, the UFSAR. The supporting material for the power uprate application is submitted as ad hoc reports and responses to j
staff requests for additional information. Some of the supporting analyses may have already been submitted, perhaps only for information, in such forms as a core operating limits report for the most recent core reload.
j If the license amendment does not specify the new analyses and codes, they do not become part of the licensing basis. Mentioning them in the SER is not enough.
i These observations are not unique to Fermi 2.
They are common to all i
completed uprate reviews. Furthermore, because of the standard nature of the reviews in the GE power uprate program, it is less likely that observations 1 and 2 are indicative of actual omissions in these reviews than in the other power uprate reviews.
The December 1990 GE topical report described the methods to be used in uprate analyses. The team found, however, that the documentation of the individual i
plant uprate reviews in the GE power uprate program did not always document confirmation that the methods described in the topical report were those used l
in the plant specific uprate.
t i
The scope of the Fermi 2 power uprate review was quite extensive.~ The team i
found only two review areas included in some other uprate reviews that were not addressed in the Fermi 2 review (except of course for PWR-specific areas):
(1) human factors and (2) ths impact of the uprate on General Design Criterion j
(GDC) 17, Electric Power Systems, considerations (10 CFR Part 50, Appendix A).
i Consideration of human factors was included in the Hatch and Nine Mile Point
}
reviews. Consideration of GDC 17 was included in the submittals that were j-based on the Westinghouse methodology described in Westinghouse report WCAP-i 10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water '
l Reactor Power Plant," January 1983. The Fermi 2 review, however, did include station blackout. The list of contributors to the Fermi 2 SER did not include j
reviewers in the Human Factors Assessment Branch or Electrical Engineering i
Branch.
I j
Seven other uprates used the GE BWR generic power uprate approach: Hatch, j
Limerick 1, Limerick 2, Nine Mile Point 2, Peach Bottom, Susquehanna, and f
l 20 i
l I
j.
L l
WNP-2. With the following exceptions, all of these uprate reviews shared the strengths and weaknesses of the Fermi 2 review. The plant-specific evaluation 4
i of SHEX that was prescribed by the staff position paper on the GE BWR power uprate program apparently was not provided for Limerick I or Limerick 2.
The i
Nine Mile Point 2 review did not include the standby liquid control system 1
(SLC). The Hatch and Nine Mile Point reviews included human factors.
?
The SERs for the uprates that used the GE BWR generic power uprate approach 1
listed the reviewers that contributed to the SERs. None of the SERs listed an j
electrical reviewer. For Fermi 2, Limerick 1, Limerick 2, Peach Bottom, i
Susquehanna, and WNP-2, a human factors reviewer was not listed.
For i
Susquehanna, a radiological reviewer was not listed.
l 3.2 Other Comoleted Power Ucrates I
i i
All of the other power uprates the team examined were approximately 5 percent j
or less, similar to those in the GE BWR power uprate program, i
Four of the uprates used the Westinghouse methodology from WCAP-10263:
Callaway, North Anna, Surry, and Vogtle.
In addition, the scope of the Wolf j
Creek submittal seems to have been modeled after the Westinghouse methodology.
In the Surry review, the codes used for ECCS, transient, and containment i
response analyses were identified, and their approval status was reviewid.
l For other codes, however, it was not clear from the uprate application or the SER which analyses were done with codes that were previously used and approved for that plant and which were not.
In the Callaway, North Anna, Vogtle, and Wolf Creek reviews, this statement is also true of the codes used for ECCS, transient, and containment respchse analyses.
In all cases, the power uprate SERs did not confirm that use of new codes was in accordance with conditions in the SERs that approved the codes. The reviews, in all cases, did not show.
evidence that they included consideration of changes, in knowledge and in the plant, that had occurred since the analytical codes used by the applicant were approved. The reviews also did not consider changes needed to the plant's i
updated final safety analysis report (UFSAR).
1 The scope of the Callaway and Surry reviews was the same as the scope of the Fenni 2 review (disregarding PWR-or BWR-specific review areas), except that the Callaway and Surry reviews included consideration of GDC 17 ar.d did not include consideration of station blackout. The review areas not addressed in the scopes of the North Anna, Vogtle, and Wolf Creek reviews are indicated in Table 3, which lists review areas not addressed for all twenty-two uprate reviews.
21
Table 3.
Review Areas Not Addressed in Uprate Reviews (BWRs are compared to Fermi 2 + GDC 17 + human factors, and PWRs are compared to Surry + SB0 + human factors.)
PLANT NS$$
REVIEW AREAS NOT ADDRESSED 2
Callaway W
SB0 human factors Calvert Cliffs 1 CE reactor vessel / internals stresses CRD mechanisms SG tube integrity RCPs pr'essurizer piping GDC 17 SB0 EQfire protection control room habitability LOCA/MSLB containment performance safety-related pumps NPSH post-LOCA combustible gas control service water CCW SFP cooling HVAC human factors Calvert Cliffs 2 CE (same as for Unit 1)
D.C. Cook 2 M
reactor vessel / internals stresses CRD mechanisms SG tube integrity RCPs pressurizer piping SB0 EQfire protection control room habitability safety-related pumps NPSH service water CCW SFP cooling HVAC radwaste circulating water system main steam human factors 22
i PLANT NSSS REVIEW AREAS NOT ADDRESSED i
l Fermi 2' GE GDC 17 human factors i
Fort Calhoun CE reactor vessel / internals stresses CRD mechanisms SG tube integrity RCPs l
pressurizer piping LOCA/MSLB containment performance l
safety-related pumps NPSH post-LOCA combustible gas control service water i
HVAC EQfire protection circulating water system i
main steam main turbine SB0 human factors Hatch' GE GDC 17 l
Limerick I' GE GDC 17 human factors Limerick 2' GE GDC 17 human factors Maine Yankee 1978 CE GDC 17 SB0 safety-related pumps NPSH post-LOCA combustible gas control 4
I&C setpoints human factors l}
(Systems, structures, & components were not specified; merely general statement that staff evaluated effect of uprate on structures & systems) 23 i
l
PLANT NSSS REVIEW AREAS NOT ADDRESSED Maine Yankee 1989 CE reactor vessel / internals stresses CRD mechanisms SG tube integrity RCPs pressurizer piping GDC 17 SB0 safety-related pumps NPSH post-LOCA combustible gas control i
service water system I&C setpoints SFP cooling HVAC fire protection circulating water system main steam main turbine control room habitability human betors i
Millstone 2 CE reactor vessel / internals stresses CRD mechanisms RCPs pressurizer GDC 17 SB0 MSLB containment performance safety-related pumps NPSH post-LOCA combustible gas control service water system CCW SFP cooling HVAC fire protection circulating water system main steam l
main turbine human factors Nine Mile Point 2' GE GDC 17 SLC i
2 North Anna M
post-LOCA combustible gas control l
HVAC fire protection SB0 human factors 24
l l
l PLANT NSSS REVIEW AREAS NOT ADDRESSED Peach Bottom 2/3' GE GDC 17 l
human factors St. Lucie 1 CE RCS flow AFW j
RHR reactor vessel / internals stresses l
CRD mechanisms l
SG tube integrity RCPs pressurizer riping LOCA/MSLB containment parformance safety-related pumps NPSH post-LOCA combustible gas control service water l
1 fire protection l
radwaste systems human factors St. Lucie 2 CE
{same as for Unit 1) 2 Surry M
SB0 human factors l
Susquehannd GE GDC 17 human factors Vogtle' M
fire protection SB0 human factors Wolf Creek' M
safety-related pumps NPSH human factors WNP-2' W
GDC 17 human factors iotes:
'This uprate followed the GE BWR uprate approach.
2This uprate followed the Westinghouse uprate approach or scope.
I The remaining uprate reviews were earlier uprate reviews and did not follow a generic uprate methodology established in a topical report. Compared to the 25 l
i 1
4 i
reviews discussed above, they were quite limited in scope, as can be seen from Table 3.
~
Some of the variability between reviews in the areas covered may be a result of inconsistent application of the assumed reactor power by different reviewers during the original reactor licensing review.
If an area was not 2
addressed in the uprate SER or RAI, it'was listed as not addressed in the i
i review. Many reviewers, particularly in the DBA consequence reviews, assumed the stretch power level (105% of maximum power) while others used the guidance in Reg. Guide 1.49 (102% of maximum power). Therefore, in a particular area, the uprated power may have been determined to be within the original licensing basis.
In these cases a reanalysis would not be necessary. However, if a technical area was not re-reviewed because the current licensing basis was still bounding, the power uprate SERs should have clearly documented it.
With one exception, the remaining uprate reviews did not appear to satisfy the i
criteria identified earlier in this section. The exception is that in the 1989 Maine Yankee review, the reviewer assessed analyses that used unapproved methods, although the reviewer did not mention that the SBLOCA analysis was not done using the recently approved SBLOCA code RELAPSYA.
A noteworthy aspect of the Millstone review was the cover letter for the power uprate amendment. This letter documented the staff's finding that certain licensee actions were needed and indicated that the licensee's staff had agreed to supply documentation of these actions on the schedule indicated in the letter.
(The license amendment itself changes only the technical specifications and the paragraph in the license that refers to the technical specifications.) This is an example of staff reliar.ce on informal licensee communication loosely tied to an " informal licensee commitment."
3.3 GE BWR Extended Power Unrate Proaram In February 1995 GE Nuclear Energy submitted a licensing topical report entitled " Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate." The report contained proposed guidelines to be followed by BWR licensees in preparing requests to increase the thermal power up to 120 percent of the original licensed thermal power.
In February 1996 the staff sent to GE Nuclear Energy the staff's position paper regarding the proposed extended power uprate program. The position paper presented the staff's position concerning (1) the expected content of individual licensee submittals, (2) the scope and depth of review topics, (3) approved.
methodologies to be used in' evaluating selected review topics, (4) licensing approach and criteria for extended power uprate, (5) expected review schedules for individual licensee amendment requests, and (6) specific limitations to f
the use of the power uprate program.
In March 1996, GE Nuclear Energy submitted a licensing topical report entitled
" Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate," which provided generic bounding ~ analyses and equipment evaluations.
This topical report and the one issued in February 1995 both incorporated the lessons learned from the previous stretch power uprate program.
In July 1996, i
Monticello, the lead plant for the BWR extended power uprate program, i
26
submitted its application for a power uprate of 6.3 percent. The staff is j
currently reviewing both the Monticello application and GE's March 1996 j
topical report.
Under the NRR Task Action Plan for the BWR Extended Power Uprate Program established in April 1995, the staff plans to develop a Standard Review -
Procedure for BWR uprates. This Standard Review Procedure will be based on j
(1) the staff position paper and the SER on GE's BWR extended power uprate 1
generic analyses, and (2) the SER on the lead plant. The Standard Review i
Procedure will be applicable for both extended and stretch power uprates, with a few minor differences.
i j
3.4 Conclusions I
i Examination of power uprate reviews reveals the need for standardization of license amendment application reviews and integration of technical review conclusions into licensing and licensing basis documents.
Another indication of the need for guidance regarding scope and depth of uprate reviews comes from the independent safety assessment of Maine Yankee.
1
-The assessment team identified mechanical components for which operability at 3
the upgraded power level could not be confirmed.-
The scope and depth of the uprate reviews varied substantially. This 1
conclusion is apparent, not only from Table 3 and the above discussion of how i
codes were considered, but also from the identification in the SERs of the reviewers that contributed to the SERs. Some SERs did not list contributors; p
others identified only the project manager. Of those that listed technical reviewers, the number of technical review branches identified ranged from two to eight, and those that listed eight did not list the same eight.
i The uprate applications and reviews surveyed covered some or all of Standard S
Review Plan (SRP) Sections 4.2, Fuel System Design; 4.3, Nuclear Design; 4.4, Thermal and Hydraulic Design (of core); and 15, Accident (and transient)
Analysis; but several do not go beyond the scope of these sections. The scope of the later uprate reviews is more extensive than that of the earlier reviews,, since applicants for the later uprates had the benefit of the GE and j
Westinghouse guidance for uprate submittals. However, the team found some variation in scope and some variation in the number of technical review branches identified, even among the later reviews. The significance of the l
variation in scope can be assessed by involving the technical review branches j
in the development of a standard review procedure for power uprates.
(See Section 3.5, recommendation (2).)
4 Usually when a. power uprate SER refers to a re-analysis, the SER doesn't state whether the re-analysis was done with the original code or with another code.
In most of the cases where the licensee. performed analyses for the first time using a new code, there is no evidence that an evaluation was performed to determine the effect on safety margin of using the new code. Future SERs i
a should make clear whether the original code was used. The reviewer should i
identify all codes used in uprate analyses and should also identify the codes i
that have been approved for performing those analyses for that reactor.
If a 27 e
i I
different code has been used, a baseline run at the old power level should be made with the new code. This baseline run will assist in estimating the effect on safety margin from the new code, as opposed to the effect of the uprate. The reviewer should assess whether approved codes are up to date with respect to relevant changes in knowledge, regulations, guidance, and changes in the plant, and should assess the use of approved codes with respect to code SER conditions. For unapproved codes, an assessment of the codes and their application to the analyses is needed.
Uprate reviews should consider all cumulative potential decreases in safety margin that have occurred, over the years (since the systems were last ana'yzed) from successive plant and procedure modifications, including the proposed uprate. The team did not find evidence that this was consistently done.
A recent situation at Brunswick suggests that reviewers should also compare the results of uprate analyses with the technical specifications to confirm that they are consistent. A 5% power uprate amendment was issued for Brunswick on November 1, 1996. During the course of the power uprate review the licensee and NRC staff believed that the torus design temperature listed in the UFSAR of 220*F was correct. On November 4, 1996, the licensee reported that the Technical Specifications (Design Features section) listed a more
- restrictive value of 200*F for the torus design temperature. At the former licensed power level of 2436 MWT, the licensee will not exceed the 200*F limit under accident conditions; however, they could exceed it under power uprate conditions (2558 MWT) for the Station Blackout event.
(The licensee has committed to limit power to the former licensed power level until t' > issue is resolved.)
Required changes resulting from the review and open items at the end.of the review should be incorporated in license conditions or technical specifications. Again, it does not appear that this was consistently done.
The team found no indication that reviewers identified changes that should be made to the UFSAR as a result of the uprate.
Some of the above observations have implications for license amendments in i
general. The observations regarding variation in scope of reviews, number of technical review branches involved, apparent lack of review of selection and use of some codes, lack of consideration of cumulative potential decreases in safety margin, and lack of integration of uprate analyses and review conclusions into licensing and licensing basis documents have general applicability.
Some observations from other sources. confirm the need for general guidance for reviewing license amendments. Several individual plant conversions from unique plant technical specifications to the standard technical specifications were done without technical branch involvement in the review or concurrence on the conversion packages. Among the conclusions in the Millstone Lessons Learned Task Group Report is that the NRC's licensing process should better i
identify the important aspects of plant-specific licensing actions and assure that those aspects are captured in the appropriate licensing document, and the 28 v- - - -
P inspection and licensing processes should work together more closely in choosing and verifying those aspects that need verification.
In the recently concluded generic spent fuel pool action plan, the staff found that some plants' UFSARs did not reflect modifications that had been made to their spent fuel pools.
In the same study, the staff also found that certain parameters identified in SERs were critical and should be, but were not, specified for followup in the inspection program. A recent event notification documented an instance in which an amended technical specification was inconsistent with its basis.
3.5 Recommendations Based on the team's review, the following recommendations have been developed:
(1) The PN Handbook should be changed to highlight the need to confirm that power uprates are incorporated into the next update of the UFSAR. The project manager (PM) is not required to review UFSAR updates for incorporation of license amendments, such as power uprates. Section 3.4.13 of the PM Handbook states that UFSAR changes should be' reviewed to ensure that they are covered by licensing actions, 10 CFR 50.59 reports, or regional inspection activities.
However, it does not address verification that license amendments are appropriately reflected in UFSAR updates. Review guidance should be provided for the PM with respect to what information from a licensing application should be incorporated in the UFSAR.
(2) A power uprate review procedure should be developed.
An uprate review procedure is needed to guide project managers and technical reviewers. The staff has a Standard Review Plan, but that document guides the technical review of specific ' systems and parts of an application for a construction permit or operating license. The. staff has no procedure for handling an application for a power uprate or other application for a Itcense amendment. No guidance, such as an NRR office letter, tells the PM or technical reviewers what the scope of an uprate review should be and what questions to ask and points to consider.
The proposed procedure should:
(1) specify how analytical codes and their use should be reviewed, (2) include guidance on review of licensee analyses and technical specifications, (3) alert the reviewer to the need to consider all cumulative potential decreases in safety margin that have occurred over the years (since the systems were last analyzed) from successive plant and procedure modifications, including the proposed uprate, (4) identify the technical review branches that should contribute to the review, (5) specify what information should be provided, by the PM, on the history and open items for the plant, (6) specify what followup is needed regarding license conditions and UFSAR update, and (7) clearly indicate the differences between a stretch power uprate review and an extended power uprate review. The scope and depth of review should be established based on a review of (1) the Standard Review Plan, as supplemented by the results of the Standard Review Plan Update and Development Program, (2) the staff position paper and the SER on GE's SWR power uprate generic analyses, and (3) uprate submittals that were l
based on the GE and Westinghouse topical reports on uprates.
l 29
i 1
l In the NRR Task Action Plan for the BWR Extended Power Uprate Program, the l
i staff is already planning to develop a standard review procedure for BWR uprates, based on (1) the staff position paper and the SER on GE's BWR extended power uprate generic analyses, and (2) the SER on the lead plant. A j
review procedure for PWRs is also needed.
l (3) The GE generic power uprate program and extended power uprate program should be reviewed against the standard review procedure that is developed for power uprates, and adjustments should be made to the programs as appropriate.
(4) The completed power uprates for which supplementary reviews were performed should be re-evaluated as appropriate against the criteria developed 1
i in the standard review procedure for power uprates, to confirm the general i
conclusions of the reviews.
i j
These re-evaluations need not be done imediately. All of the completed power uprate reviews were for uprates of approximately 5 percent or less.
In a study documented in NUREG-1230, " Compendium of ECCS Research for Realistic LOCA Analysis," December 1988, the staff concluded that the potential risk impact from a 5 percent power increase is expected to be small and likely to be within the uncertainty of the present PRA methodology. Furthermore, in the Statement of Considerations for the 1988 rule revising the ECCS acceptance criteria, the Commission stated the position that the increase in fission products available for release during a postulated core meltdown, due to a 5 percent power increase, is negligible compared to the uncertainty in fission product release. Thus, these power uprates do not appear to pose an immediate safety issue.
(5) The NRR office letter on license amendments, Office Letter 803, should be revised to provide additional general guidance for planning, performing, and closing out a review of a license amendment request. Because a license amendment has potential health & safety implications, amendments should be planned and closed out carefully.
The technical branches that have responsibility for the technical areas involved in the amendment should be given the proposed amendment for review. Those technical branches involved in the amendment should develop a position, at the outset of the review, on what the scope & depth of a review of such an amendment request should be, if such a position has not already been developed. What documents, or portions of documents, should be reviewed or followed should be indicated. The review should be followed up with appropriate integration of analyses and review conclusions into licensing and licensing basis documents and the inspection program. For any staff SER that approves the use of a new code or methodology, it should be identified in the proposed Tech spec bases section.
The PM should ensure that the appropriate parts of every license amendment, such as power uprates, are incorporated into the UFSAR.
In addition, before concurring on the action, the PM's and technical reviewers' supervisors should verify that the review has been parformed properly. This office letter, which can include the guidance on uprate reviews, should be incorporated into NRR's training program.
30
- 4. ISSUE CLOSURE AND INTERFACE ISSUES 4.1 Closecut of TNI Action Itame 1
]
The team contracted with Scientech, Inc., to conduct a document search to i
locate and compile the closeout documentatic for TMI Action Plan Items j
II.K.3.5, II.K.3.30, and II.K.3.31 for all plants currently holding an j
operating license. Documents were examined to develop a general understanding of the review process applied to each item by the staff and to identify
]
potential problem areas in the closeout. Specifically, technical staff involvement in the closecut of each item for each affected plant was assessed, i
along with management oversight of the closeout documents and safety i
evaluations in the closecuts.
4.1.1 Closecut Issues 4.1.1.1 TMI Action Plan Item II.K.3.5 l
This action plan item addressed trip criteria for reactor coolant pumps (RCPs) at PWRs during LOCAs. The NRC staff issued Generic Letters (GLs)83-10a
)
through 83-10f to PWR applicants and licensees providing guidance for the development of either satisfactory setpoints for RCP trip or technical bases i
for allowing continued RCP operation in the event of a small-break LOCA' (SBLOCA).
In GL 85-12, the staff concluded that the generic information provided by the Westinghouse Owners Group (WOG) in support of alternative RCP trip criteria was acceptable on a generic basis. Applicants and licensees of Westinghouse plants were requested to choose from among three ~ alternate RCP trip criteria.
In GL 86-05, the staff concluded that the generic information provided by the B&W Owners Group (BWOG) in support of the loss-of-sukooling RCP trip criterion was acceptable. The staff also requested plant specific information about instrument uncertainties, potential RCP problems, operator training, and procedures.
In GL 86-06, the staff concluded that the generic information provided by the Combustion Engineering Owners Group (CEOG) in support of the trip two/ leave-two staggered RCP trip criterion was acceptable. The staff also requested plant specific information about instrument uncertainties, potential RCP
~
problems, operator training, and procedures.
The technical staff reviewed the plant-specific information and prepared SERs for about half of the affected plants between 1986 and 1988.
Letters from PMs forwarded the SERs to the licensees and documented closeout of the issue. By mesorr.ndum to all Project Directors dated March 3,1989, the Chief of the Reactor Systems Branch stated that the reviews of plant-specific information had progressed to a degree that the staff could conclude that the BWOG, CEOG, and WOG methodologies had significantly improved reactor safety and that there were no major safety-significant concerns for the plant-specific information.
On this basis, the issue was considered closed for all remaining plants except Haddam Neck. From March 1989 through early 1990, the issue was closed for the 31
~
[
I remaining plants (except Haddam Neck) by letters from the PM to the licensee using the wording provided in the March 3, 1989, meno.
Haddam Neck remained open because the Connecticut Yankee Atomic Power Com)any did not endorse the WOG methodology. The issue was closed for Haddam Necc after staff review and approval of the plant-specific SBLOCA analysis, which indicated that RCP trip was not required for Haddam Neck. The closecut was i
documented in a letter from the PM to the licensee dated May 10, 1989, in which the technical staff and the Project Director concurred.
1 4.1.1.2 TMI Action Plan Items II.K.3.30 and II.K.3.31 In response to these items, GE provided information to demonstrate that its existing SBLOCA evaluation model (EM) complied with 10 CFR 50.46, taking into consideration comparisons with experimental data. By letter to GE dated December 13, 1983, the staff forwarded its SER on the GE submittal. The staff concluded that the GE EM was "very conservative" in predicting peak cladding temperatures (PCTs) for SBLOCAs and was therefore acceptable for prediction of 58LOCA transients in licensing submittals.
In December 1983 and January 1984, letters to GE licensees from licensing branch chiefs (projects) in NRR, stated that, based on the generic GE SE, Items II.K.3.30 and II.K.3.31 were closed for those plants. Since the existing EM was demonstrated to be acceptable, no further plant-specific analysis was required.
Within the group of facilities receiving engineering services from Yankee Atomic Electric Company (the Yankee group), Vermont Yankee was covered by this generic effort.
Items II.K.3.30 and II.K.3.31 were closed for Vermont Yankee by letter dated January 4, 1984.
Four plants under construction (Grand Gulf, La Salle, Susquehanna, and WNP-2) had committed to the GE generic effort. The staff accepted those commitments in the respective SERs. The team was unable to locate documentation of the closeout of this ites. Supplemental SERs for each plant and the respective dockets were searched for the period immediately following issuance of the generic SER on the GE EM.
It is recommended that the applicability of the generic GE EM to these four facilities be verified.
(See Section 4.1.3.)
Westinghouse submitted a new licensing EM, NOTRUMP, as described in Westinghouse topical report, WCAP-10079. By letter to Westinghouse dated May 21, 1985, the staff forwarded its SER regarding NOTRUMP. The staff. concluded that NOTRUMP was an acceptable computer program for use in performing licensing calculations of SBLOCAs for Westinghouse-designed NSSSs. The staff also stated that its review fulfilled the requirements in TMI Action Plan Item II.K.3.30 for computer code validation, and that NOTRUMP was therefore the acceptable code'for TMI Action Plan Item II.K.3.31 application.
In May through July 1985, affected licensees were informed in letters from NRR licensing branch chiefs that, based on the May 21, 1985, SER, Item II.K.3.30 was closed for their plants and that plant-specific applications of NOTRUMP should be submitted within one year. On June 11, 1986, Westinghouse submitted topical report WCAP-11145, " Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study with the NOTRUMP Code."
In an SER dated October 6, 1986, the staff found that in WCAP-11145, the guidance of TMI Action Plan Item 32
i i
II.K.3.31, as clarified by GL 83-35, had been satisfied. Subsequent letters from project managers to licensees informed them that, based on their 4.
referencing WCAP-lll45, Item II.K.3.31 was closed. Therefore all Westinghouse plants, except Haddam Neck, had approved SBLOCA methodologies using the l
approved WCAP-lll45.
)
Within the Yankee group, Seabrook was covered by the Westinghouse generic effort. The staff closed Item II.K.3.30 for Seabrook by letter dated June 11, 1985, forwarding the staff's generic SER of May 21, 1985. By letter dated January 6, 1987, the staff accepted the licensee's referencing WCAP-11145 for Seabrook and closed Item II.K.3.31.
4 i
In response to TMI Action Plan Item II.K.3.30, the CEOG elected to justify i
continued acceptance of the CEFLASH-4AS computer program for SBLOCA evaluation. The CEOG response was transmitted it, a generic topical report CEN-203, " Response to NRC Action Plan Item II.K.3.30 Justification of Small Break LOCA Methods." By letter to the CEOG dated June 20, 1985, the staff forwarded its SER regarding CEFLASH-4AS. The staff concluded that, pending an acceptable benchmark comparison of CEFLASH-4AS with Semiscale experiment S-UT-t 08, Action Item II.K.3.30 was resolved for CE plants. With an acceptable calculation / data comparison, the staff found that the requirements to perform j
a plant-specific analysis would no longer apply to the CE plants except Maine Yankee. On December 31, 1985, the CEOG submitted topical report CEN-203, Revision 1-P, Supplement 3 and Revision 1-P, Supplement 4 in response to the staff's concern that the CEFLASH-4AS computer program might not be able to calculate the initial rapid drop in water level experienced in the simulated reactor vessel in the Semiscale Test S-UT-08. The staff provided its review of these supplements in a letter dated February 11, 1987. The staff found that the CEFLASH-4AS program acceptably calculated the test. On this basis, Action Plan Items II.K.3.30 and II.K.3.31 were closed for the CEOG licensees except MYAPCo (Maine Yankee). The team's review raised a question regarding the applicability of this generic effort to San Onofre Nuclear Generating Station, Units 2 and 3 (SONGS 2/3) which is addressed in Sections 4.1.1.3 and 4.1.3.
In response to TMI Action Plan Item II.'K.3.30, the BWOG submitted a modified CRAFT 2 EM in topical report BAW-10092(P), Rev. 3, " CRAFT 2 - FORTRAN Program for Digital Simulation of a Multinode Reactor Plant During Loss of Coolant" (Proprietary) and non-proprietary version designated BAW-10154(NP). By letter to Babcock & Wilcox dated June 27, 1985, the staff issued a generic safety evaluation accepting the B&W topical reports for referencing in license i
applications.
In letters to the affected licensees in July and August 1985, the staff requested that each licensee confirm within 45 days that the BWOG position on noncondensable gases was the licensee's position and that the BWOG commitment to compare the CRAFT 2 LOCA analysis results with the Multiloop Integral System Test Facility (MIST) results was also the licensee's commitment. The team verified receipt of each licensee's confirmatory response. The BWOG provided the MIST LOCA test results on July 31, 1989.
In accordance with the guidance regarding Item II.K.3.31 in GL 83-35, the BWOG submitted topical report BAW-1976 to demonstrate that the generic CRAFT 2 i
analysis results conservatively bounded the existing licensing basis ECCS SBLOCA analyses for lowered loop B&W plants. The BWOG also submitted topical 33
report-BAW-1981 to provide the bounding analysis for raised loop plants. The staff reviewed these topleal reports and closed II.K.3.31 for the affected plants in mid-1989. There were no B&W facilities not covered by this effort.
4.1.1.3 Technical Staff Involvement The closeout documents were reviewed to assess technical staff involvement.
Technical staff involvement included preparation of a generic SER, preparation of a plant-specific SER, or concurrence in a closeout letter. Where the closeout was documented in a Supplement to the Facility Safety Evaluation Report, technical staff involvement was inferred.
In some cases, internal memoranda were located to verify technical staff involvement.
One concern was identified. By letter dated May 21, 1987, Southern California Edison Company cited the staff's approval of the CEOG generic methodology as the basis for concluding that no further licensee action was required regarding TMI Action Plan Items II.K.3.30 and II.K.3.31 for San Onofre Nuclear Generating Station (SONGS), Units 2 and 3.
By letter dated July 17, 1987, the PM informed the licensee that the staff considered those items closed for SONGS 2/3. The PM cited as basis the licensee's letter of May 21, 1987. The PM's letter did not have concurrence from the technical staff. The team was unable to locate an internal memorandum providing input to the PM's letter.
The project director (PD) ccncurred in the letter.
(See Section 4.1.3.)
4.1.1.4 Management Oversight i
The team examined each closecut document to assess management oversight and involvement. Where the closecut was documented in a Supplement to the Facility Safety Evaluation Report, management oversight was inferred.
Concurrence by an acting Project Director other than the originator of the document was considered to constitute acceptable management oversight. Lack of management oversight was deemed to exist when no management concurrence was indicated or when the originator of the document concurred on behalf of management.
The team identified three closeout' letters which were issued without Associate Director for Projects (ADPR) management concurrence. Each of these letters enclosed a safety evaluation prepared by the technical staff regarding plant-i specific analyses pursuant to Item II.K.3.31.
These closeout documents were
]
similar to several dozen others which were issued with management concurrence.
Issuance of these documents did not raise any concerns.
l The team identified nine closeout documents in which the originating PM
(
concurred on behalf of management, signifying acknowledgement that management j
involvement was required. One of the nine was the May 8, 1989, letter which i
closed Item II.K.3.31 for Maine Yankee. Two others forwarded safety evaluations prepared by the technical staff for plant-specific analyses pursuant to Item II.K.3.31. These two documents were similar to several dozen l
others which were issued with management concurrence. Five of the nine 1etters closed Item II.K.3.5.
Two of the five issued safety evaluations which had been prepared by the technical staff and were similar to other closecut letters which included management concurrence. The team compared the 34 l
remaining _ three to the generic closecut guidance provided by the technical staff in a memorandum dated March 3, 1989. The three letters were consistent with the technical staff closecut guidance and similar to several dozen other letters issued with appropriate management concurrence. The last item in which the originating PM concurred on behalf of management was a TS amendment regarding a change in fuel supplier. As part of the review of that amendment, the technical staff had reviewed the licensee's plant-specific SBLOCA analysis using the generic Westinghouse EM which had previously been approved for the subject plant pursuant to Item II.K.3.30.
In conjunction with the issuance of the amendment, the staff closed Item II.K.3.31. The team had no concerns about this item. Of the nine documents, the team found that eight were 1
acceptable as they contained appropriate technical justification and technical staff involvement. One product, the May 8, 1989, letter to Maine Yankee, was found to be an outlier.
In summary, the team identified three documents which had no management
)
concurrence, and nine documents in which the PM concurred on behalf of J
management. The team compared these documents to other closeout documents
)
which had appropriate management concurrence. The May 8, 1989, letter to Maine Yankee, was identified to be the sole outlier.
4.1.1.5 Safety Evaluations The closecut of each item for each affected plant was reviewed for documentation of the staff's evaluation of the licensee's response? Item II.K.3.30 was typically closed via a generic SER forwarded to the affected owners group plants.
Item II.K.3.31 was also typically closed by a staff SER describing the staff's review of the plant-specific or generic bounding SBLOCA analysis.. Notable exceptions include the Maine Yankee application regarding RELAP5YA and the Haddam Neck application regarding NULAP5.
The Maine Yankee code RELAP5YA was approved in a safety evaluation dated October 14, 1988, which was forwarded to the licensee by letter dated January 17, 1989. The Maine Yankee SER contained 12 conditions on the acceptable application of the code. Maine Yankee was the only plant that did not make a submittal to satisfy the guidance in Item II.K.3.31.
The Haddam Neck code, NULAP5, and a plant-specific analysis using NULAP5 were approved with nine conditions in a safety evaluation dated August 3, 1988.
The licensee submitted another plant-specific LOCA analysis in January 1991 using a best estimate upper plenum injection model in conjunction with an amendment application related to conversion from stainless steel clad fuel to Zircaloy clad fuel. The staff accepted that analysis in conjunction with the issuance of the fuel conversion amendment on January 17, 1992. The acceptance included exemptions for the model from certain requirements of Appendix K to 10 CFR Part 50.
Item II.K.3.5 was closed for about half of the affected plants (PWRs) before 1989 by issuance of SERs describing the staff's evaluation of the plant-specific information provided in response to GLs 85-12, 86-05 and 86-06. By memorandum dated March 3, 1989, the Reactor Systems Branch provided generic closeout guidance for the remaining plants (except Haddam Neck) stating that 35
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the staff's review of the plant-specific information had concluded that no safety-significant concerns remained. No SERs were issued with these closeout letters. The Haddam Neck closecut is discussed under Item II.K.3.5 above and enclosed a safety evaluation prepared by the technical staff.
For Maine Yankee, Item II.K.3.5 was closed via SER dated April 15, 1986. The SER was prepared by the technical staff after meeting with the licensee and j
receiving the licensee's responses to staff questions on non-LCCA issues related to Item II.K.3.5.
The licensing branch chief concurred in the issuance of the SER to the licensee.
l 4.1.2 Followup / Verification Process i
The Safety Issues Management System (SIMS) indicates that.the three subject TNI Action Plan Items did not require verification. Nonetheless, NUDOCS was j
used to identify inspection reports related to these three items.
Four reports for II.K.3.30 and another four related to II.K.3.31 were identified.
These Region inspection reports documented NRR closure of the cited issue but did not indicate any further follow up..The team notes that the review of the plant-specific analysis submitted pursuant to II.K.3.31 using the EN approved by the staff pursuant to II.K.3.30 provided verification of licensee
)
implementation of the approved EM.
The team identified 48 inspection reports related to Item II.K.3.5.
A i
representative sample of these reports, including reports from each Region, were evaluated. The inspections examined licensee responses to the GLs i
related to Action Plan Item-II.K.3.5 and verified that the statenents made by the licensees in their submittals had been appropriately incorpo ated into plant procedures. These reports generally concluded that licenrees had conformed to their commitments regarding reactor coolant pump trip. Where concerns were raised by the inspectors, appropriate inspector follow items were opened. The team concluded that the verification performed regarding Item II.K.3.5 provided reasonable assurance that licensees had conformed to their commitments regarding implementation of procedures regarding reactor coolant pump trip.
4.1.3 Recommendations Based on the team's review, the following recommendations have been developed:
(1) The technical staff should verify the applicability of the GE effort to Gra.1d Gulf, La Salle, Susquehanna, and WNP-2, and document the basis in a memo to the docket file. The team was unable to verify the closecut of TMI Action Plan Items II.K.3.30 and II.K.3.31 for Grand Gulf, La Salle, Susquehanna, and WNP-2. Each of these facilities' licensees had committed to the generic GE effort which the staff found to be conservative. Therefore the team did not have an immediate safety concern.
(2) The technical staff chould verify the applicability of the CE0G effort to SONGS 2/3 and document it in a memo to the docket file.
(See Sections 4.1.1.2
,i
)
and 4.1.1.3.)
Items II.K.3.30 and II.K.3.31 were closed for SONGS 2/3 based on a letter frca the licensee stating that the staff's generic approval of the 36 1
4 l
CEOG methodology applied to that facility. No technical staff involvement in that closecut was documented. The team did not have an immediate safety 1
concern because the CEOG effort involved demonstration that the existing EM was adequate taking into consideration comparison to test facility experiment results. Provided that the CEOG methodology is applicable to SONGS 2/3, no concern exists.
(3) A Temporary Instruction should be developed to enable inspectors and/or project managers to audit the implementation of Item II.K.3.31 by reviewing i
plant operating parameters derived from the cycle-specific analysis to understand that a logical progression of safety analysis has been followed.
Specifically, selected plant parameters should be validated against the S8LOCA code of record, and the code of record should be_ assessed against the original approved SBLOCA code developed to conform with the guidance in Item II.K.3.30.
j This entire process should be completed as part of a 10 CFR 50.5g review.
l (See Section 4.1.2) Region inspectors conducted selected reviews of the
{
impismentation of reactor coolant pump trip strategies. This adequately addressed implementation of licensee commitments regarding Item II.K.3.5.
Regarding II.K.3.30 and II.K.3.31, no inspection activity was identified which verified licensee implementation of the ECCS ems following closeout of Items II.K.3.30 and II.K.3.31. The Maine Yankee experience involves a licensee making apparently unacceptable changes to the approved model without reporting to the Commission as required by 10 CFR 50.46.
i 4.2 Staff Interfaces The team assessed various staff guidance documents, including Management i
Directive ~s, NRR Office Letters, and the Project Manager's Handbook (NUREG/BR-0073, Revision 1), for guidance regarding documentation of communications with licensees, technical staff involvement, signature authority, and tracking of licensee commitments.
4 In addition to evaluating the adequacy of staff guidance documents, current j
staff performance in the areas discussed below was benchmarked by reviewing
)
i selected documents generated by the projects organization within NRR during the first half of calendar year (CY) 1996. The documents reviewed included a broad sampling of licensing action approvals and denials, and generic issue
)
evaluations. The sample included at least two documents for each operating power reactor. A total of 257 documents were reviewed. The sample included i
115 amendments, of which E were emergency amendments and 7 were exigent i
amendments. The remair.ing documents included exemptions, reliefs, Code cases, l
task interface agreements, and plant-specific topical report evaluations. The results of the review are indicated in the appropriate sections below.
4.2.1 Documentation of Communications with Licensees The team found little written guidance to project managers on documentation of communications with licensees. Discussions with project managers indicated i
that they are aware of the need to document communications with licensees when those communications form or contribute to the basis for a licensing decision.
Some PMs maintain contemporaneous notes of phone calls. Most PMs request that licensees provide information on the docket which was provided in telephone 37
conversations when that infomation forms the basis of a licensing decision.
On rare occasions, telephone conversations are documented in a memo to the E
docket file. These menos were not used to form the basis for a licensing decision.
A NUDOCS search for documentation of telephone conversations during the first half of CY 1996 revealed thirteen documents. Only three of those involved the licensee.
It was concluded that PMs generally do not document telephone conversations that are deemed to be of minor significance, and that for telephone conversations involving infomation of significance to a licensing decision the licensee documents the information in a letter on the docket to the staff.
It is recommended that NRR management clearly define and document expectations of project managers regarding documentation of communications with licensees.
These expectations should take into consideration that PMs routinely conduct mundane conversations for which formal documentation would constitute an undue burden. Any information which forms _ the basis of a pending staff licensing decision must be provided by the licensee on the docket.
(See Section 4.2.5.)
of note is that the Process Improvement Plan of ADPR includes development of a position in this area.
4.2.2 Technical Staff Coordination and Concurrences The team evaluated various guidance documents related to coordination between the project manager and the technical staff and to appropriate levels of These guidance documents included NRR Office Letters, the concurrence.
Project Manager's Handbook, and NRC Management Directives.
l NRR Office Letter (OL) 803, Revision 1, " Technical Specifications Review Procedures," dated February 27, 1996, provides guidance and assigns i
responsibilities to NRR staff involved in the review of license amendment requests or the development of new technical specifications. OL 803 indicates that the project manager is responsible for determining the appropriate level 4
of technical staff involvement in the review of a proposed license amendment.
Specifically, the OL states that " Staff from the technical branches shall work with the project manager, as reauested...," and "If asked by the orofect manager, personnel from the technical branches shall assist..." (emphasis added). The OL goes on to state that the project manager shall coordinate technical staff involvement in the review. Finally the OL indicates that the project manager shall ensure that the review and concurrence chain includes all of the individuals responsible for the quality of the document. The technical staff should review and concur if (1) the technical staff did not prepare the SER, or (2) the technical staff prepared the SER and the project manager has made substantial changes to the SER.
OL 803 provides guidance and assignment of responsibility to ensure appropriate coordination between the project manager and the technical staff, and appropriate technical staff concurrence in the review of license amendment applications.
(But see racommendations 3.5(2) and 3.5(5).) OL 803 does not address coordination of other licensing actions such as requests for reliefs or exemptions.
It also does not address coordination of other tasks such as 38
i resolution of generic issues, event reports, 50.59 reviews, response to task i
interface agreements from the regions, requests for interpretations from licensees, 2.206 Directer's Decisions, and controlled correspondence.
i of the 257 documents reviewed, 32 did not contain direct technical staff involvement by either preparation of or concurrence in the document. The team 2
i reviewed the content of these documents. Typically they (1) corrected 1
typographical errors in previous NRC documents (2) involved administrative i
changes to plant technical specifications, (3) enclosed standard safety evaluations for Generic Letter responses, or (4) denied licensee applications.
The team did not identify any concerns regarding the content of these 32 i
documents.
)
In evaluating the ability of the PM to fulfill expectations regarding obtaining appropriate concurrences, it was noted that the PM must have clear t
guidance on which branch (es) in the ADT organization are to be involved in
~
each individual review. To ensure that the PM has adequate information on i
organizational responsibilities within NRR, function-oriented organizational i
charts reflecting those responsibilities at the Section level should be promulgated with each re-organization.
(See Section 4.2.5.
Also see i
recommendation 3.5(2).')
i 4.2.3 ' Signature Authority l
The staff guidance documents related to signature authority and concurrence j
were evaluated. These guidance documents included NRR Office Letters, the Project Manager's Handbook, and NRC Management Directives.
i l
On review of the May 8,1989, letter from the project manager to Maine Yankee, l
it is the team's understanding that the licensee was of the opinion that this letter superseded a previous staff position that required the submittal of a j
plant-specific SBLOCA analysis using the previously approved code, RELAP5YA.
i The staff's signature authority, as designated in.0L 101, " Delegation of j
Signature Authority," does not specifically address the circumstance of general correspondence to a licensee which reverses an existing staff i
i position. However, management expectations and the intent of OL 101 suggests i
that the May 8, 1989, letter should have required at least the technical staff j
Division Director's signature, possibly the Office Director's.
In addition, i
the change of licensee commitments previously made in writing by a telephone conversation in which the commitment revisions involve substantive regulatory I
and technical issues clearly should have involved senior technical staff l
management involvement and concurrence.
Of the 257 documents reviewed, in ten cases the originating project manager signed or concurred as the acting project director, effectively bypassing management oversight. OL 101, Revision 11, issued on August 9, 1996, includes a footnote which states that, "To ensure appropriate independent review, when a
a non-supervisory staff member is acting for the supervisor, the staff member should not concur and/or sign on their own work. The staff member should obtain concurrence or signature from another cognizant supervisor, or the next higher level of management." The team concludes that this revision addresses the concerns identified from the May 8,1989, letter and suffices as direction 39
to ensure appropriate management oversight in the future where supervisor concurrence is required.
Within the ADPR organization, PDs are afforded latitude in the amount of involvement required in overseeing products issued from NRR. Specifically, this effort identified that supervisor concurrence is not always required.
Some senior, experienced project managers are authorized to sign and issue various correspondence without obtaining PD concurrence. Of the 257 documents reviewed, 46 did not include any PD concurrence. Of those 46, the project director was not on distribution for 12. Thus about 18% of the products reviewed had no opportunity for PD oversight.
OL 101 indicates that the Project Director signs. approvals and denials specified in 10 CFR 50.55a. Of the 257 documents reviewed, 66 involved approvals or denials of i_nservice inspection and inservice testing (ISI/IST) programs, Code reliefs, and Code alternatives. Of the 66, eight were inappropriately signed by the project manager. The project director concurred in five of those eight. The PD was on distribution of the other three. The team did not have any concerns regarding the content of these eight documents.
No signature authority problems were identified for any other type of document.
It is recommended that ADPR staff be reminded of the signature authority for approval or denial of licensing requests pursuant to 10 CFR 50.55a.
(See Section 4.2.5.)
An inconsistent standard has evolved within the ADPR organization.
In some cases, if a Senior Project Manger concurs as acting PD in an amendment package he/she originated, such action would be contrary to Revision 11 to OL 101. In other cases, some project managers are not even required to obtain PD concurrence in an amendment.
In the case of the May 8, 1989, letter to Maine
. Yankee, the concurrence by the Project Manager in lieu of his supervisor was cited'by the 0!G as a significant weakness.
It is recommended that management ensure uniformity and consistency in assuring appropriate oversight of the licensing program. Specifically, license amendments are significant regulatory actions requiring, as a minimum, first-level supervisor oversight.
It is noted that such actions contain other checks and balances in the process, including independent reviews by the licensing assistant, technical staff, and the Office of General Counsel.
In addition, other licensing actions such as reliefs and exemptions require a higher level of management involvement. Products that would not normally require Senior Executive Service (SES) level involvement unless a sensitive or unusual issue was involved include meeting summaries, memoranda to file, and routine correspondence. This matter could best be addressed in a further revision of OL 101.
(See Section 4.2.5.)
40
4.2.4 ' Tracking Licensee Commitments Staff guidance related to licensee commitments contained in the Project Manager's Handbook was evaluated.
The guidance discusses written utility commitments and notes that such commitments are not binding on the utility.
It further states that, to the extent that such commitments are judged to be a necessary element to support an acceptable-finding, they should be spelled out clearly in the SER. The inference drawn is that, although the commitment is not binding on the utility, a change to the commitment would undermine the basis for the staff's acceptance ai,d therefore requires prior staff approval.
The guidance notes that a commitment may be given " enforcement strength" by order. The guidance states that "any failure to live up to [a e m itment imposed by order) bears a stronger enforcement penalty than if it were simply a written comitment."
From this a reader could infer that there was some binding enforcement sanction, albeit a lesser one, for failure to live up to a written commitment without a confirmatory order. This contradicts the aforementioned statement that such a comitment is not binding on the utility.
The guidance addresses the handling in the licensing process of written utility commitments which are deemed to be a necessary part of approval of a licensee's proposal. The guidance does not address tracking or follow-up verification of such commitments.
It also does not address the management of lower order commitments such as schedular commitments, or commitments provided verbally (e.g., at. inspection exit meetings, licensing meetings, or in telephone conversations.)
Of the 257 documents reviewed, 13 identified licensee commitments which formed the basis of the staff's approval and 6 placed conditions on the staff's approval.
In December 1995, the Commission endorsed the Nuclear Energy Institute (NEI) guidance on licensee comitment tracking (SECY-95-300).
In a staff meeting in early 1996, project managers were informed that licensees may be implementing the guidance and that project managers would be expected to review their licensee's comitment tracking system. No formal guidance has been issued.
It is recommended that NRR management issue clear, fermal guidance on the various levels of licensee comitments, including exp6ctations of the project managers regarding commitment tracking and verification, interaction with the Regions in verification of licensee commitments, and project manager oversight of licensee comitment tracking systems.
(See Section 4.2.5.)
The team notes that ADPR's Process Improvement. Plan includes development of guidance on documentation of verbal comitments.
4.2.5 Recommendations (1) NRR management should clearly define and document expectations of project managers regarding documentation of communications with licensees. These expectations should take into consideration that PMs routinely conduct mundane conversations for which formal documentation would constitute an undue burden.
41
i 1
They should also recognize that the staff has routinely relied on licensee i
recollections of past conversations becaus~e no NRC documentation of the conversations survived. Any information which forms the basis of a pending
}
staff licensing decision must be provided by the licensee on the docket.
(2)
In evaluating the ability of the PM to fulfill the' expectations regarding obtaining appropriate concurrences, it is noted that the PN needs clear 4
guidance on which branch (es) in the technical staff are cognizant for each of the various technical areas. To ensure that the PN has adequate information on organizational responsibilities within NRR, function-oriented organuzational charts reflecting those responsibilities at the Section level should be promulgated with each re-organization.
(3) ADPR staff should be reminded'of the OL 101 signature authority for 1
approvals and denials pursuant to 10 CFR 50.55a. The team found that 12% of these items were signed by the project manager rather than the project f
director as required by OL 101. The project director had concurred in most of those documents.
(4) NRR management should ensure uniformity and consistency in assuring l
appropriate oversight of the licensing program. Specifically, license amendments are significant regulatory actions requiring, as a minimum, first-level supervisor oversight. The team notes that such actions contain other checks and balances in the process, including independent reviews by the licensing assistant, technical -staff, and the Office of General Counsel.
In 4
}
addition, other licensing actions such as reliefs and exemptions require a higher level of management involvement. Products that would not normally require SES level involvement unless a sensitive or unusual issue was involved j
include meeting summaries, memoranda to file, and routine correspondence.
This matter could best be addressed in a further revision of OL 101. The team 1
notes that ADPR's Procen Improvement Plan includes revision of OL 101.
i j
(5) NRR management should issue clear, formal guidance on the various levels i
of licensee commitments, including expectations for the project managers regarding conunitment tracking and verification, interaction with the Regions in verification of licensee cossaiteents, and project manager oversight of licensee commitment tracking systems.
4 l
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4 i
l 42
)
LIST OF ABBREVIATIONS ABB Asea Brown Boveri ACRS Advisory Committee on Reactor Safeguards ADPR Associate Director for Projects, NRR ADS automatic depressurization system ADT Associate Director for Technical Review, NRR AFW auxiliary feedwater system' ATWS anticipated transient without scram B&W Babcock and Wilcox BWR boiling water reactor BWOG B&W Owners Group CCW component cooling water system CE Combustion Engineering CEOG Combustion Engineering Owners Group COLR core operating limits report CRD control rod drive CY calendar year DBA design basis accident DRPE Division of Reactor Projects I/II, NRR DRPW Division of Reactor Projects III/IV, NRR DSSA Division of Safety Systems and Analysis, NRR ECCS emergency core cooling system EDO Executive Director for Operations EM evaluation model EQ equipment qualification FSAR Final Safety Assessment Report FTI Framatome Technologies, Inc.
GDC General Design Criterion GE General Electric GL generic letter HVAC heating, ventilating, and air conditioning I&C instrumentation and control IEEE Institute of Electrical and Electronics Engineers ISI/IST inservice inspection and inservice testing LBLOCA large-break loss-of-coolant accident LCO limiting condition for operation LOCA loss-of-coolant accident MIST Multiloop Integral System Test Facility MOV motor operated valve MSLB main steam line break MWt megawatts thermal MYAPCo Maine Yankee Atomic Power Company NEI Nuclear Energy Institute.
NPSH net positive suction head NSSS nuclear steam supply system NRR Office of Nuclear Reactor Regulation OGC Office of General Counsel OIG Office of the Inspector General OL NRR Office Letter OTSG once through steam generator 43
f PCT peak clad temperature PO project director POI-3 Project Directorate I-3, NRR PM project manager PWR pressurized water reactor QA '
quality assurance RAI request for additional information, RCP reactor coolant pump RCS reactor coolant system RCIC reactor core isolation cooling system RHR residual heat removal system RSG recirculating steam generator SASG Analytical Support Group, NRR 58LOCA small-break loss-of-coolant accident SB0 station blackout SER safety evaluation report, whether it is entitled " Safety Evaluation Report" or " Safety Evaluation" SES Senior Executive Service SFP spent fuel pool SG steam generator SIMS Safety Issues Management System SLC standby liquid control system SONGS San Onofre Nuclear Generating Station SPC Siemens Power Corporation SRP Standard Review Plan SRX8 Reactor Systems Branch, NRR TER,
technical evaluation report TMI Three Mile Island TS technical specification UFSAR updated final safety analysis report M
Westinghouse WNP-2 Washington Public Power Supply System Nuclear Project No. 2 WOG Westinghouse Owners Group YAEC Yankee Atomic Electric Company 44 r
m
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APPENDIX l
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PLAN TO ADDRESS LESSONS LEARNED FROM MAINE YANKEE EXPERIENCE l
l l
l
~_.
O,* #Ce,g*
g UNITED STATES g
j NUCLEAR REGULATORY COMMISSION t
WASHINGTON, D.C. 3000HOO1 April 25, 1996 j
i MEMORANDUM T0: Ashok C. Thadani, Associate Director for Technical Review Office of Nuclear Reactor Regulation j
)
FROM:
Gary M. Holahan, Director Division of Systems Safety and Anal is Office of Nuclear Reactor Regulation
SUBJECT:
PLAN TO ADDRESS LESSONS LEARNED FROM MAINE YANKEE EXPERIENCE By memorand"m dated January 5, 1996, you requested DSSA to take several actions related to the recent Maine Yankee experience involving the inappropriate use of the RELAPSYA code for analyses in justification for power uprata, We have developed the attached pl % which provides an outline of the i
actiom, the staff will take to address the issues discussed in your memorandum. We have formed a team to implement the plan consisting of a team leader, Phil Cota, Amy Cubbage from the Reactor Systems Branch, and Dan Dorman from Reactor Projects. Amy Cubbage will work on the project 100 percent of her time (works part-time schedule), Phil Cota will work on the project for 60 percent of his time, and Dan Dorman will work on the plan for 25 percent of his time.
In addition, Ralph Caruso will provide soport to the team in the area of identifying and evaluating options with regwJ to a catalogue of codes. We have also attached a timeline for implementing the plan which provides our schedule to complete these activities in 5 months.
1
Attachment:
As stated cc: 4.'4cta D. Dorman R. Caruso W. McDowell (OIG) l l
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PLAN TO ADDRESS MAINE YANKEE ISSUES BACKGROUND As the result of an allegation, the staff became aware of the inappropriate use of the RELAP5YA code for analyses in justification for power uprate for the Maine Yankee plant.
There were several contributing factors to this occurrence. This situation has prompted the staff to begin a self assessment to determine if improvements should be made in certain areas.
The following outline details NRR's plans to evaluate the technical review, item closure, and-interface aspects of the problem. This will address the code review l
process, the power uprate review process, closure and followup of TMI action l
items, and the process of staff coordination.
?
l I TECHNICAL REVIEW PROCESS ISSUES l
Issue I-1:- Is the code review process adequate? Specifically, do staff l
evaluations meet the goals of clarity, consistency and completeness of review l
in determining the acceptability and appropriateness of the code for its i
intended use?
r l
Responsibility:
A. Cubbage Relationship to Maine Yankee:
It was determined that RELAP5YA was not applied for Maine Yankee in a manner conforming to the requirements of 10 CFR Part 50.46 and Appendix K nor had it been applied in a manner conforming to the conditions l
specified in the staff's SER, as necessary for NRC acceptance of the use of RELAP5YA for small break loss of coola% accident (SBLOCA) analyses for Maine Yankee. As a result, the stafi wncluded that the SBLOCA portion of the ECCS analyses performed for Maine Yankee cycle 15 does not conform with the requirement of'10 CFR 50.46.
Planned actions:
L 3a) Evaluate staff review of code submittals by:
Comparing the staff review of several similar LOCA codes for consistency in approach and quality of the review by addressing the following areas:
Documentation Level of detail of RAls 1
Experimental verification required (separate effect/ integral test)
NRR management oversight and review ACRS review l
Test problems / standard problem comparison Ser.sitivity study required (noding, time step, etc.)
l Conditions attached to SER a
5 i
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d e
- Determining need for guidance to standardize review precess in the following areas:
i Example plant calculations Define documentation requirements Define standard problems Define sensitivity study criteria i
Evaluate the need for Reg Guide Reference sample of other codes l
Resources: ' Contract Support: 3 Staff-months ($60K) i j
Technical staff Support: 4 Staff-weeks for evaluation lb) Evaluate the code modification review process / followup on I
licensee / vendor implementation through the fo11, Sg reviews:
For code changes that are submitted to the staff for review, examine the same areas discussed above for the initial code
- review, i
Core operating limits report process - determine if guidance in GL 88-16 needs to be modified to be more specific with regard to SER conditions Review the results of completed audits / inspections to determine the need for aciitional emphasis in this area 3
Determine if the Core Performance Action plan should be modified, in light of the results of the above sub-tasks, to i'
include more emphasis in the area of code implementation by 1
licensees and vendors witis an emphasis on how SER conditions are satisfied Resources:
Technical staff 6 staff-weeks Ic) Evaluate options for a catalogue of codes and related approvals, limitations, and conditions Identify potential options (COMPLETE)
Evaluate the following cptions:
1.
Licensee documentation of compliance with conditions; 2.
NRC Catalogue of analytical license requirements; 3.
Elimination of conditions in SERs for general methodological models; and 4.
Elimination of approval for general methodological models.
Prepara recommendations Resources:
Phil Cota (2 staff-weeks) with support from SRXB member and i
Ralph Caruso as necessary i
Issue 1-2:
It the staff review process for power uprates adequate? What are its strengths and weaknesses? How can it be improved?
Responsibility:
Phil Cota Relationship to Maine Yankee:
RELAPSYA was used inappropriately in support of Maine Yankee's power uprate. As a result the staff will consider whether the power uprate review process was a contributing factor in this problem, and whether the level of detail of current and future power uprate reviews is sufficient to prevent similar problems.
l Planned actions:
l Revisit all completed power uprate SERs to determine if the scope of review was adequate.
How did the staff assure that codes are properly implemented for supporting analyses (pay particular attention to how code SER conditions are used)?
l How did the staff review the impact of the power uprate on the Technical Specifications?
l How did the staff followup on the incorporation of power l
uprate changes into modifications of design basis documents?
Determine if additional staff guidance is required Resources: Contract support 8 staff-weeks ($40K)
Phil tota 2 staff-weeks l
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e
4 II ISSUE CLOSURE AND INTERFACE ISSUES Issue 11-1: Was the closecut of TMI action items done properly?
l Responsibility:
D. Dorman Relationship To Maine Yankee:
TMI action item II.K.3.31 stated the NRC position that plant-specific.
calculations using NRC-approved models for SBLOCA, as described in item II.K.3.30 to show compliance with 10 CFR 50.46, should be submitted for NRC approval by all licensees, and that the calculations shall be submitted by January 1,1983 or 1 year after staff approval of LOCA analysis models, whichever is later. _TMI action item II.K.3.30 was closed for Maine Yankee by letter dated January 30, 1989, which forwarded staff approval of the computer code RELAP5YA as a licensing method for small-break LOCA analyses.
A~cordingly, plant-specific c
calculations were supposed to be submitted to the NRC by January 30, 1990 (one year after approval of the model).
However, the item was i
closed based on a commitment that Maine Yankee would perform plant l
specific calculations using RELAPSYA for CYCLE 12 reload analyses.
The l
staff's letter did not specifically require any further submittals for closure of this item, but did indicate that licensee implementation of the code may be subject to future inspection.
The fulfillment of the licensees commitment was never verified by the staff.
l Planned Actions:
Review the closeout of TMI Action items ll.K.3.30, II.K.3.31, and II.K.3.5 on all applicable plants Identify potential prob'em areas Identify issues that were closed out in a manner similar to ll.K.3.31 (i.e., no technical staff concurrence, no safety evaluation, no plant-specific submittal).
Review followup process for regional and headquarters verification of closure of items Review NUREG-1435 and safety issues management system (SIMS) data for vulnerable areas Review problem areas identified above for adequacy of closeout Were issues closed out based on commitments, and did staff followup to verify completion?
Determina if a change is warraited in the proc..s for closing out issues and develcp additional staff guidance as appropriate j
l Resources:
25% of Projects Team Member's tine for 1 month Contract support I staff-month (520K) 5
1 l
Issue 11-2: Are the interfaces between the NRR projects organization and the licensees, and between the NRR projects organization and the NRR technical staff adequate?
l Responsibility:
D. Dorman 1
Relationship to Maine Yankee:
l As discussed above, the closure of TMI action item II.K.3.31 was based on a commitment from the licensee.
Closure of this item was communicated to the licensee by a letter from the NRR project manager.
This letter was signed out by the project manager without concurrence from the technical staff or from projects management.
The letter closing this item in effect superseded the requirements of TMI action item II.K.3.31.
Planned Actions:
Evaluate documentation of communications with licensee Examine current project manager guidance for technical staff coordination and concurrences i
Examine signature authority with respect to superseding j
previous staff positions and/or requirements l
Examine current project manager guidance I
regarding how to track licensees' commitments for licensing applications Prepare additional staff guidance as necessary Resources: 25% of Projects team member's time for 1 month 1
l i
I l
)
Milestones for the Maine Yankee Lessons Learned Action Plan Team Member /
Time Sunnort Resource (From Action Plan Initiation) 0 Imth 2mth 3mth 4mth Smth SRX8 Staff
/------------/-----/-------------------/
/****
I-Ib Rpt Contract support prep Evaluate findings 4
Technical
/-----------------------/
4 Contractor I-la, I-Ib, & I-2 i
Projects Staff
/-------/-------/-------/-----/
/****
II-2 Contract 11-1 Rpt i
Support prep i
Team Leader
/--------/--------- ---------/
/--------/****
(Phil Cota)
Contract I-Ic, I-2 &
Report j
Placement Contract support Prep.
1
a Timeframe Activities 0 to 1 month Team Leader oversees the bidding and placement of the Technical Contract with, support from the SRXB Team Member.
SRXB Team Member assists with contract and begins in-house review of item I-Ib.
Projects team member begins review of Projects / Tech Staff / Licensee interfaces (11-2)
Analytical Support begins item II-Ic.
I to 2 months Technical contractor begins work on items Isla, I-lb, 1-2, and 11-1.
Items expected to be worked in parallel with 3 months to completion.
Projects team member finishes Projects / Tech Staff / Licensee interfaces (11-2) and begins review of TMI Action items closeout (item Il-1)
SRXB Team Member completes in-house portion of item Ib.
Analytical Support completes item !!-lc.
2 to 3 months SRXB Team Member prepares report on in-house reviews.
Team Leader begins report preparation.
3 to 4.5 months Team Leader and SRXB Team Member evaluate the findings of the Technical Contractor (items 1-
{
la, 1-lb, and I-2)
Some results are expected to be available prior to completion of the Technical Contractor phase.
. Projects team member completes review of TMl action item closure using the documentation obtained from the contractor.
4.5 to 5 months Team drafts final composite report.
]
Note: These milestones are predicated on applying 100% of the SRXB team member's time (works part-time schedule), and 60% of the team leader's time 4..d 25% of the projects team member's time to this project.
l l
,