ML20134K698
| ML20134K698 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/16/1995 |
| From: | Eliason L Public Service Enterprise Group |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20134J860 | List: |
| References | |
| FOIA-96-351 LR-N95132, NUDOCS 9702140158 | |
| Download: ML20134K698 (7) | |
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Leon R. EHason Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 080 609-339-1100 CNet Nuclear officer & President l
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United States Nuclear Regulatory Commission i{
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Document Control Desk Washington, DC 20555 i
Attn:
Richard W.
Cooper, II 6
l Director - Division of Reactor Projects, Region I g p6/
Dear Mr. Cooper:
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This letter is in response to the NRC's letter of June 5
to E. James Forland, Chief Executive Officer, Public Service h/g i
f Electric & Gas Company, relating to information received by the 1/f 1
i NRC concerning Fitness for Duty concerns at the Salem Generatin
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l Station.
The attachment to that letter, which was withheld from public disclosure pursuant to 10 CFR 2.790(a), contained further details of the allegation.
Public Service Electric & Gas requests that Attachments 1 and 2 to this letter, which contain the details of the response to your request, be withheld from public disclosure pursuant to 10 CFR 2.790.
In support of such request, an affidavit is enclosed.
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Sinceral i
L. R. Eliason Chief Nuclear Officer &
President-Nuclear Business Unit
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Attachments (2)
TEE ATTACEMENTS TO TEIS LETTER CONTAIN INF TION E WITERELD FRON PUELIC DISCLO E
PURS 0 CFR 2.79
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Information in this record was dcNed k
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O'NEILL96-351 PDR
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With Attachments C
Mr. T. T. Martin, Administrator - Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Without Attachments Mr. L. N. 01shan, Licensing Project Manager - Salem U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 14E21 Rockville, MD 20852 Mr.
C. S. Marschall USNRC Senior Resident Inspector Salem Generating Station Mr. K. Tosch, Manager IV NJ Department of Environmental Protection Division of Environmental Protection Bureau of Nuclear Engineering CN 415 Trenton, NJ 08625 T** n'f"f'unENTS TO T ER CONTA NFORMATION TO B T
FROM P IC CLOSURE PURSUANT TO 10 C
.790 95 4933
Document Control Desk 3
LR-N95132 AFFIDAV SU ORTING TO WI OLD UMENTS BLIC DI E
I, Leon Eliason, being duly sworn, depose and state as follows:
1.
I am Chief Nuclear Officer and President - Nuclear Business Unit, Public Service Electric & Gas company (PSE&G) and as such I am responsibJe for the review of the information l
referenced herein scught to be withheld from public disclosure.
I am submitting this affidavit in connection with the provisions of 10CFR$2.790 of the Commission's regulations.
2.
The information sought to be withheld is responsive to the Commission's letter of June 19, 1995.
Release would compromise the information contained in the enclosure to that letter which the NRC has requested "should be controlled and distribution limited to personnel with a
'need to know'" and is considered exempt from public disclosure by the NRC.
3.
The attachments to be withheld contain privacy information, including information relating to discipline of employees I
and related to the Company's fitness for duty program, the disclosure of which could reasonably be expected to constitute an unwarranted invasion of privacy of a number of l
emp2oyees.
4.
Personnel who cooperated in the investigation which is discussed in both attachments were given assurances that, aside from sharing the results with the NRC, every effort would be taken to protect the information from disclosure.
Release could compromise the investigation and make such investigations more difficult in the future.
5.
The information in the two attachments has been designated as confidential in accordance with policies established by PSE&G for the control and protection of information and in acco'rdance with precedents for the treatment of similar material.
6.
The attachments contain information of a proprietary and confidential nature.
The information is of the type customarily held in confidence by PSE&G and not made ATTA'*'
T THIS LETTER N INFORMATION WITERE FROM P IC DIS UR V PURSU TO CFR 2.790 v
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LR-95132 available publicly.
Based on my experience, I-am aware that other companies regard information of the kind contained'in the attachments as proprietary and confidential.
7.
The information sought to be withheld is being transmitted to the Commission in confidence pursuant to the provisions j
of 10CFRS2.790 with the understanding that it is to be l
received in confidence and withheld from public disclosure by the Commission.
8.
The information sought to be withheld, to the best of my knowledge, is not available in public sources and has been
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strictly controlled within PSE&G.
Disclosure to third parties will be made pursuant only to regulatory requirements that provide for the maintenance of the information in confidence.
9.
It is also PSE&G's position that a compelling reason for nondisclosure within the meaning of 5 2.790(a) exists, in that the information sought to be withheld constitutes a critical self-analysis undertaken for the purpose of improving corporate performance, and public disclosure of such information'could undermine the important public policy interest in the promotion of candid unimpeded self-evaluation.
Accordingly, it is PSE&G's view that the need for the information to be given confidential treatment t
outweighs the public's interest in disclosure in this instance.
The above nine paragraphs are true and corr to the best of my knowledge, information and belief.
Leon it. Eliason Subscribed and Sworn to efore me this
- day
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n Nopary PubJcff (NEw Jersey KIMBERLY JO BROWN NOTARY PUBUC 0F NEW JERSEY My Commission expires on V-L "c" r,1ess l-TEE ATTACEMENTS IS LETTER CONTAIN INFORMATION TO BE WI ELD E
l SUANT TO 10 CFR 2.790
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uNrreo stares NUCLEAR REGULATORY COMMISSION g
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KING OF PRUSSIA, PENNSYLVANIA 194061415 MAR f i 1934 Docket Nos. 50-272 50-311 Mr. Steven E. Miltenberger Vice Pitsident and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038 hj'
Dear Mr. Miltenberger:
SUBIECT:
NRC REGION I COMBINED INSPECTION REPORT NOS. 50-272/9442 AND 50-311/94-02 This letter transmits the report of the announced safety inspection conducted by Mr. L. L. Scholl of this office for the periods of January 24-28 and February 7-10,1994, at the Salem Nuclear Generating Station located in Hancocks Bridge, New Jersey. 'Ihe inspector discussed the findings of this iaWon with members of your staff on February 17, 1994.
The inspection was directed towards areas important to public health and safety. Areas
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examined are described in the NRC inspection report enclosed with this letter. Within these areas, the inspection consisted of document reviews and personnel interviews.
'Ihe purpose of the inspection was to review the rod control system performance and associated maintenance and modifications performed following the rod control system Augmented Inspection Team (AIT) activities of June 1993. Procedure and program improvements implemented after the rod control system problems were also reviewed.
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'Ihe !==,r+:+x found that the rod control sym on Salem Units 1 arid 2 were operating reliably. Modifications have been performed on Unit I during the last refueling outage to further improve the rod control system reliability. Similar modifications are planned for Unit 2 during the next refueling outage.
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Public Service Electric 2
and Gas Company The lack of a comprehensive root cause analysis program was a weakness identified by the AIT. 'Ihe inspector noted that this weakness was subsequently confirmed during the PSE&G comy.h.sive performance assessment team evaluation and that a team has been formed to develop a comprehensive root cause analysis program. 'Ihe NRC acknowledges this effort and encourages PSE&G management to ensure successful implementation of a rigorous Program.
Your cooperation with us is appreciated. No response to this letter is requested.
- Sincerey, r
William H. Ruland, Chie Electrical Section G
Engineering Branch Division of Reactor Safety
Enclosure:
NRC Inspection Report Nos. 50-272/94-02 and 57-311/94-02 cc w/ encl:
J. J. Hagan, Vice President-Operations / General Wnager-Salem Operations S. LaBruna, Vice President - Engineering and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
R. Hovey, General Manager - Hope Creek Operations F. Thomson, Manager, Licensing and Regulation R. Swanson, General Manager - QA and Nuclear Safety Review J. Robb, Director, Joint Owner Affairs A. Tapert, Program Administrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. J. Curham, Manager, Joint Generation Department, Atlantic Electric Company Consumer Advocate, Office of Consumer Advocate William Conklin, Public Safety Consultant, lower Alloways Creek Township i
K. Abraham, PAO (2)
Public Document Room (PDR) l Local Public Document Room (LPDR)
Nuclear Safety Information Center (NSIC)
NRC Resident Inptor State of New Jersey
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UNITED STATES j
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NUCLEAR REOUt.ATORY COMMISSION g
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Docket Nos. 50-272 APR 61994 i
50-311 i
S3M 1-Mr. Steven E. Millenberger Vice President and Chief Nuclear Officer i..
Public Service Electric and Gas Comprny l
P. O. Box 236 l
Hancocks Bridge, New Jersey 08038 1
Dear Mr. Miltenberger:
1 SUBIECT: INSPECTION REPORT NOS. 50-272/9444,50-311/94-04, AND 50-354/94-02 This refers to the routine announced in=p~*ian conducted by Mr. Imnard Cheung and other NRC ia=r+M9fs on February 14-18,1994, at the Salem and Hope Creek Nuclear Generating Stat %s in Hancocks Bridge, New Jersey. At the conclusion of the iaea~* ion, the findings were discussed with those members of your staff identified in the enclosed report.
'Ihis inspection focused on the review of the Salem and Hope Creek environmental qualification (EQ) programs and updated the status of two NRC unresolved items regarding cable separation and the environmental qualification of certain safety-related valve position switches. 'Ihe environmental qualification program is impmi.et to public health and safety because it helps to ensure that certain equipment is available to mitigate the consequences of an accident. Within these areas, the inspection consisted of selected naminatinne of relevant procedures, representative records and audits, interviews with personnel, and observations by (y
the inspectors.
'Ihe inspectors concluded that: 1) the EQ master lists were appropriately maintained; 2) the quality assurance (QA) audits of the BQ program wese comprehensive; and 3) the responses to the QA audit findings were generally thoscugh and timely. However, the team noted that the resolution of one QA audit finding regading the equipment,
-9"- C= of the power range nuclear instru===tatina system had not been resolved and may warrant additional management sta= tina to ensure timely resolution of this issue.
In accordance with 10 CPR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosures will be placed in the NRC Public n,-==at Room.
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APR 61994 Public Service Electric 2
and Gas Company Your cooperation with us is appreciated. No written response to this letter is required.
Sincerely, 4
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William H. Ruland, Chief Electrical Section n,. p=dsg Branch Division of Reactor Safety l
Enclosure:
NRC Region I Inspection Report Nos. 50-272/94-04, 50-311/94-04, and 50-354/94-02 1
f cc w/ encl:
J. J. Hagan, Vice President-Opemtions/ General Manager-Salem Operations S. LaBruna, Vice President hp% and Plant Betterment l
C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
R. Hovey, General Manager - Hope Creek Operations F. 'Ihomson, Manager, Licensing and Regulation R. Swanson, General Manager - QA and Nuclear Safety Review i
J. Robb, Director, Joint Owner Affairs A. Tapert, Program Administrator R. Pryling, Jr., Esquire M. Wetterhahn, Esquire P. J. Curham, Manager, Joint Generation Department, Atlantic Electric Company Consumer Advocate, Office of Consumer Advocate b
William Conklin, Public Safety Consultant, Lower Alloways Creek Township K. Abraham, PAO (2)
Public Document Room (PDR) local Public Document Room (LPDR) i Nuclear Safety Information Center (NSIC)
NRC Resident Inspector State of New Jersey i
ATTACHMENT 2 MARCH 30, 1995 Mr. Leon R. Eliason Chief Nuclear Officer & Presidant Nuclear Business Unit Public Service Electric and Gas Company P. O. Box 236 Hancocks Bridge, New Jersey 08038
SUBJECT:
SALEM ENGINEERING FOLLOWUP INSPECTION 94-32
Dear Mr. Eliason:
This letter refers to the safety inspection conducted by Mr. B. McDermott of this office on December 5-19, 1994, and March 14-15, 1995, at the Salem Generating Stations and on February 13-24, 1995, at the NRC Region I office.
The inspection was focused on issues important to public health and safety, specifically, your actions taken in response to industry and NRC information regarding nonconservatisms in the setpoint of the Pressurizer Overpressure Protection System (P0PS) for brittle fracture protection of the reactor vessel. The preliminary results were discussed with Mr. J. Summers, and others of your staff, on December 19, 1994. A second exit meeting was conducted by telephone with Mr. Summers on March 23, 1995.
Four apparent violations were identified during our review of your actions to resolve the POPS setpoint nonconservatisms, specifically:
(1) your reliance on an exemption from the requirements of 10 CFR 50.60 without NRC approval; (2) failing to report a condition outside the plant's design basis (10 CFR 50.72 and 50.73); (3) revising the plant's design basis without the safety evaluation required by 10 CFR 50.59; and (4) failing to take appropriate corrective actions for a significant condition adverse to quality (10 CFR 50, Appendix B, Criterion XVI). The details of these apparent violations are discussed in the attached inspection report.
We acknowledge your position that the engineering significance of the problem was considered to be low by engineering personnel and that the plant was adequately protected. However, the fact that the issue was not entered into an arpropriate system for resolution of engineering discrepancies for over a year indicates a significant weakness in your ability to understand and effect prompt resolution of problems. Even after the issue was entered into an appropriate system, seven months passed before you determined that the plant was outside it's design bast's. Further, failure to perform a safety evaluation for changes to the POPS design bases, as required by 10 CFR 50.59, reflects a continuing weakness in your process for developing and implementing effective corrective action.
Irtrmatien in this record was deleted 7
in accordance 't.d!h the f:ceim of intornution
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I Mr. Leon R. Eliason 2
The apparent violations discussed above are being considered for appropriate l
enforcement action and, accordingly, no Notice of Violation is presently being i
issued for these findings. You will be informed by separate correspondence of i
any subsequent action required in response to the apparent violations.
Your cooperation in this matter was appreciated, and we would be pleased to discuss the conclusions described in this report with you.
y Sincerely, ORIGINAL SIGNED BY:
r James T. Wiggins, Director r
Division of Reactor Safety l
i Docket Nos. 50-272; 50-311
Enclosure:
Salem Inspection Report 94-32 cc w/ enc 1:
J. J. Hagan, Vice President-Operations l
S. LaBruna, Vice President - Engineering and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
R. Burricelli, General Manager - Informations systems & External Affairs J. Summers, General Manager - Sales Operations J. Benjamin, Director - Quality Assurance & Safety Review j
F. Thomson, Manager, Licensing and Regulation R. Kankus, Joint Owner Affairs A. Tapert, Program Administrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. J. Curham, Manager, Joint Generation Department, Atlantic Electric Company Consumer Advocate, Office of Consumer Advocate William Conklin, Public Safety Consultant, Lower A110 ways Creek Township Public Service Commission of Naryland D. Screnci, PA0 (2)
PUBLIC Nuclear Safety Information Center (NSIC)
NRC Resident Inspector State of New Jersey State of Delaware i
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3 Mr. Leon R. Eliason Distribution w/ enc 1:
Region 1 Docket Room (with concurrences)
J. Wiggins, DRS E. Kelly, DRS Kay Gallagher, DRP DRS Files (2)
Distribution w/ enc 1: (Via E-Mail)
L. 01shan, NRR W. Dean, OEDO J. Stolz, PDI-2, NRR M. Callahan, OCA Inspection Program Branch, NRR (IPAS)
DOCUMENT NAME: A:SA943232. INS Ts receive a copy of this h inacate la the bes: "C' = Copy without sh/encienne "E' = Copywith attachsneet/eaciosase if" = No copy 0FFICE RI/DRS RI/DRS RI/DRS RI/DRS l
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NAME DMcDermott/dag EKelly JWiggins DATE 07/21/95 07/
/95 07/
/95 07/
/95 07/
/95 0FFICIAL RECORD COPY
U. S. NUCLEAR REGULATORY COMMISSION REGION I DOCKET / REPORT NOS:
50-272/94-32 50-311/94-32 LICENSEE:
Public Service Electric & Gas Company FACILITY:
Salen Generating Stations Hancocks Bridge, New Jersey DATES:
December 5-19, 1994 February 13-24, 1995 March 14-15, 1995 ORIGINAL SIGNED BY:
3/24/95 t
INSPECTOR:
Brian J. McDermott, Reactor Engineer Date Systems Section l
Division of Reactor Safety ORIGINAL SIGNED BY:
3/24/95 APPROVED BY:
Eugene M. Kelly, Chief Date Systems Section Division of Reactor Safety
SUMMARY
PSE&G worked to resolve nonconservatisms in the Pressurizer Overpressure Protection System (POPS) setpoint calculations for approximately two years (March 1993 through February 1995).
In the process, PSE&G relied on an exemption from the requirements of 10 CFR 50.60 without NRC approval, failed to report a condition outside their plants' design-bases, and revised the POPS design-basis transient (described in the FSAR and Technical Specification Bases) without performing a safety evaluation pursuant to 10 CFR 50.59. During the inspection, engineering personnel stated that from the time the issue was identified in March 1993 they considered its safety significance to be low and that the plant was adequately protected. However, the POPS issue was not entered into an appropriate system for evaluating operability, safety significance, or reportability for over a year while options to assuage the problem were explored. After the issue was entered in an appropriate
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system,-the design basis for POPS was changed and the evaluation required by j
10 CFR 50.59 for identification of a possible unreviewed safety question, was 4
not performed. Several apparent violations of NRC requirements identified i
during this inspection are being considered for enforcement action. The licensee's calculations for the revised POPS design-basis transient have been referred to the NRC Office Of Nuclear Reactor Regulation for review and pending their evaluation, this aspect of the issue will be unresolved.
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DETAILS
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1.0 INSPECTION SCOPE 1
i This inspection evaluated the response of Public Service Electric and Gas l
(PSE&G) to information regarding the nonconservatisms identified in the technical specification setpoints for the pressurizer overpressure protection j
i system (POPS) at both Salen units. The nonconservatisms in the original i
Westinghouse setpoint methodology were communicated to PSE&G in a letter from 15, 1993. NRC Information Notice 93-58, the vendor dated March "Nonconservatism in Low-Temperature Overpressure Protection for Pressurized-Water Reactors," dated July 26, 1993, reiterated the problems identified by Westinghouse.
i-2.0 FININGS i
Backaround t
t The POPS uses two pressurizer power-operated relief valves (PORVs) to mitigate j
low temperature (<312*F) overpressure transients, keeping the peak pressure j
below the limits of 10 CFR 50, Appendix G, " Fracture Toughness Requirements,"
for brittle fracture protection. The Appendix G limits are incorporated in technical specifications (TS) as pressure-temperature (P/T) curves specific to The original design-basis mass addition transient each unit's reactor vessel.
for the POPS was based on the start of a safety injection pump (780 gpa) and its injection into a water solid reactor coolant system (RCS).
POPS was designed to meet the single failure criterion, with either PORY having sufficient relief capacity to limit the peak pressure to less than the P/T carve limit.
Aq NRC safety evaluation report, dated February 21, 1980, associated with Amendment No. 24 to the Unit 1 TS, approved the Salem POPS setpoint of 375 pounds per square inch gage (psig), based on the calculated peak transient pressure of 446 psig and a 14 psi margin (at that time) below the Unit 1 Requirements for the lhit 2 POPS were Appendix G limit of 460 psig.
incorporated into the unit's TS prior to initial startup and were approved based on the Unit 1 POPS safety evaluation.
The P/T limits for all reactor vessels decrease with successive operating cycles due to irradiation effects on the vessel materials. Therefore, margin between the peak transient pressure and the P/T limit will change as The subsequent revisions of P/T curves are reviewed and approved by the NRC.
Salem Unit 1 P/T curves were revised in February 1990 in TS Amendment No.108, which established a more restrictise limit of 450 psig at low temperatures.
The Unit 2 P/T curves were approved (at the same time) in TS Amendment No. 86, which established a limit of 475 psig. These curves are valid for up to 15 effective full power years of operation.
Setooint Nonconservatism On March 15, 1993, Westinghouse issued a Nuclear Safety Advisory Letter (NSAL-93-005B) informing PSE&G about the nonconservatisms in the setpoint The dynamic head, resulting from running reactor methodology for POPS.
coolant pumps (RCPs) and the static head, due to elevation of sensors relative
l 2
to the reactor vessel midplane, were found not to have been considered in the original setpoint methodology. The static head error for Salem is relatively small, resulting in a 4.7 psi increase in the peak transient pressure.
However, the dynamic head error is more significant. Each operating RCP will increase the difference between pressure at the reactor vessel midplane and that sensed by the. POPS instrumentation by approximately 25 psi.
Consequently, for a four-loop plant such as Sales, the sensed pressure (with all four RCPs running) could be as much as 100 psi less than the actual I
pressure at the reactor vessel midplane (the area of concern for P/T curves).
These errors simply can be added to the original peak transient pressure since their effect is to offset (nonconservatively) the pressure at which POPS will actuate. NRC Information Notice (IN) 93-58, "Nonconservatism in Low-Temperature Overpressure Protection for Pressurized-Water Reactors," was issued on July 26, 1994. The IN noted that administrative restrictions, I
i recommended by the Westinghouse NSAL, were intended to provide interin actions I
until either setpoints were verified to be accurate, or appropriately revised in TS.
In December 1993, after reevaluating (over a nine month period) the original i
POPS analysis to address the NSAL concerns, PSE&G determined that the corrected peak transient pressure would exceed the P/T limits of both units.
Even with limiting the number of running RCPs to two, the corrected peak pressure would be 485 psig (applicable for either unit since the analyzed transient is the same). On December 30, 1993, the licensee dispositioned the issue by memorandum (MEC-93-917), administrative 1y limiting the. maximum number of RCPs in service to two when RCS temperature was below 200*F (limiting the dynamic error in the most restrictive area of the P/T curve), and increasing each unit's P/T limit by 10% using an unapproved American Society of Mechanical Engineers (ASME) Code Case N-514. The inspector noted that, at temperatures above 200'F and up to 312'F, the Appendix G P/T curves allow for much higher pressure limits.
The inspector considered that - at the point PSE&G became aware that the margins to TS P/T limits for Appendix G brittle fracture considerations were not only reduced but, in fact, lost (and the Appendix G limits could be potentially exceeded) - both Salen Units could be potentially operated in an unanalyzed condition (whenever below 312*F) which would be outside the plants' Therefore, the condition was reportable, and the licensee's design bases.
failure to make such a report is an apparent violation of the reporting (EEI 50-272;311/94-32-01) Further, the requirements of 10 CFR 50.72 and 73.
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inspector noted that an exemption request for use of ASME Code Case N-514 had Use of the ASME code not been submitted by PSE&G until late December 1994.
case would require preapproval by the NRC, either generically via regulatory l
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guide or specifically for Salem by exemption from 10 CFR 50.60.
licensee's reliance on the then unapproved ASME Code Case N-514 for over one year without the required exemption is an apparent violation of 10 CFR 50.60.
(EEI 50-272;311/94-32-02)
Less than one month after the issued had been dispositioned in Memorandum MEC-93-917, the licensee recognized that the ASME code case could not be used l
The licensee then sought to credit the capacity i
without prior NRC approval.
of the residual heat removal (RHR) suction relief valve RH3 to augment the
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analyzed POPS relief capacity. The spring-operated relief valve (RH3) has the j
same setpoint as POPS, but has a greater effective flow area and will actuate faster than a PORV once its setpoint is reached. A subsequent analysis by j
PSE&G confirmed the licensee's initial judgement that, with RH3 available, the peak pressure would remain below the Appendix G limit. The issue of crediting l
RH3 as part of POPS (without either a 50.59 safety evaluation or prior NRC approval by changing the POPS TS) was under consideration from mid-January through mid-April 1994. On April 19, 1994, a Discrepancy Evaluation Form (DEF 94-0060) was written to document the fact that relief valve RH3 was not i
credited the original POPS analysis for Sales or in the existing licensing and i
design basis (the NRC safety evaluation) for the system. The inspector noted that at this point, PSE&G had attempted to resolve the issue for over a year without entering the fundamental engineering question (the adequacy of the I
POPS setpoint) in either of the two existing PSE&G quality systems for i
resolution of Sales engineering discrepancies (the Incident Report System or DEF process)..The inspector concluded that the licensee's failure to initiate corrective actions for this significant condition adverse to quality, is an i
apparent violation of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action."
(EEI 50-272;311/94-32-03)
Corrective Action Process Initiated The April 1994 DEF addressed the immediate safety concern by assuring the j
availability of relief valve RH3 and considering the safety margins discussed j
in the ASNE code case. At this time the licensee also initiated a procedure i
revision to limit the number of running RCPs in Mode 5 (below 200"F) to one i
pump, thus further minimizing the dynamic head error in the most restrictive Since the licensee concluded that there was no region of the P/T curves.
I immediate operability concern, they sought to find other reasons why the i
The inspector noted Westinghouse nonconservatism did not apply to Salem.
i i
that, even after the issue was entered into the PSE&G DEF process, the 1
condition outside the design basis was still not reported to the NRC.
j The inspector independently assessed the availability and capability of relief valve RH3 for supplementing the POPS. Valve RH3 is available for RCS pressure relief when the RHR system is aligned for shutdown cooling. Review of Sales integrated operating procedures 10P-2, " Cold Shutdown To Hot Standby," and 10P-6, " Hot Standby To Cold Shutdown" showed that RHR shutdown cooling will be 1
in service when POPS is required to be operable (<312"F). One reason valve RH3 was not credited by the NRC in the original 1980 POPS analysis was that an automatic closure interlock would shut the RHR suction valve on high RCS i
pressure, isolating RH3 from the RCS. However, this interlock was removed from both Salem units in the late 1980's. This change was generically l
reviewed by the NRC under Westinghouse Topical Report WCAP-Il736, " Residual Heat Removal System Autoclosure Interlock Removal Report," and was subsequently approved by the NRC in a safety evaluation, dated 4
August 8, 1989. The inspector also reviewed the valve's relief capacity, actuation response time, and calibration schedule. The inspector concluded j
that valve RH3 would be available to supplement POPS based on the procedural 4
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4 requirements and would substantially reduce the peak transient pressure based on its design. However, crediting valve RH3 as part of POPS would, in the inspector's estimation, require a change to the Salem Technical i
j Specifications.
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The issue was once again closed (by memorandum, dated 5/26/94), based on a procedural requirement to achieve a pressurizer " bubble" (saturated conditions j
l with a steam space) before starting a RCP. Because of this requirement, it was reasoned that only a correction for static head was necessary (relatively l
a small effect); therefore, the original analysis was concluded by PSE&G to be still valid. The inspector noted that the procedural requirement to have a i
pressurizer " bubble" before starting any RCPs was in place, and had been l
previously reviewed in the 1980 NRC safety evaluation report for POPS.
Although the DEF was closed by PSE&G via this memorandum, further analyses to support license changes for (crediting valve RH3 and using the ASME code case) 1 were continued in anticipation of future, more restrictive revisions to the P/T curves. -During this analysis, the licensee determined that.the effects of a running RCP on the POPS analysis should also be considered. However, no formal 50.59 safety evaluation had as yet been performed.
Revised Desian-Basis Transient On September 27, 1994, Problem Report (PR) No. 940927126 was initiated after the licensee determined that they could not rely on the establishment of a pressurizer " bubble" to resolve the problem. Since the original POPS analysis would not provide acceptable results after the effects of running RCPs were considered, engineering personnel established what they considered a more
" realistic" transient as the design basis event for POPS.
The original transient was simply the start of a safety injection pump (the intermediate head pump delivers 780 gps) and its injection into a water-solid RCS. The licensee's revised transient is mechanistic and relies upon procedural controls for limiting possible injection sources. The revised transient begins with the reactor in Mode 5 (<200"F), the positive displacement (PD) charging pump in service and one RCP running, whereafter an inadvertent safety injection (SI) signal would cause the centrifugal charging pump (high head SI at 560 gps) to start, the PD charging pump to trip, and the l
isolation of letdown to the chemical and volume control system.
Evaluation of this transient (mitigated by a single PORV having a 375 psig setpoint) using the GOTHIC computer code resulted in a predicted peak pressure of 438 psig, below the P/T limits of each unit. Therefore, by limiting the magnitude of the mass addition, the licensee was able to reduce the predicted peak transient pre sure and justify the existing TS setpoint for POPS.
By the end of September 1994, the licensee believed they had reached a final resolution and closed the issue (for the third time in nine months) because the revised transient could be mitigated by the original POPS hardware with the existing 375 psig TS setpoint. Although the licensee had not changed the TS setpoint, they had changed its technical justification by revising the limiting transient upon which the setpoint is based. The relevant Technical Specifications for the Salem Unit 1 POPS are 3.4.9.3 and Bases 3/4.4.9.3; For Salem Unit 2 they are TS 3.4.10.3, and Bases 3/4.4.10.3.
Further, the new L
7 1
i 5
transient, which changed the design basis for POPS, also invalidated the NRC's The SER upon which Amendment No. 24 - and both units' POPS TS - was. based.
l description of the limiting transient and the design bases for POPS in Sales FSAR Section 7.6.3.3 were, therefore, no longer correct and current.
1 The inspector noted that, since March 1993, several PSE&G corrective action programs were used but none was effective in resolving the Salem POPS issue.
Another (more recent) opportunity to evaluate all the relevant considerations of this issue was missed: as of the conclusion of the exit meeting on December 19, 1994, no safety evaluation was performed to determine if the change in the POPS design-basis transient had created an "unreviewed safety 10 CFR 50.59 requires licensees to evaluate changes to the plant question."
or its procedures (including methods and modes of operation), prior to those The changes being effected, to assure no unreviewed safety question exists.
licensee's failure to perform this safety evaluation is, therefore, an apparent violation of 10 CFR 50.59.
(EEI 50-272;311/94-32-04)
"New" Transient Amended l
In November 1994, the licensee recognized that an error - recently identified in their configuration baseline document - would adversely effect their The configuration assumptions for the revised POPS mass addition transient.
document had incorrectly assumed that the positive displacement (PD) charging l
pump trips off on a SI signal; however, if off-site power is available when l
the SI signal occurs, the pump continues to run and trip signals are blocked (until the SI signal is reset). After discovering this error, analysis for the limiting POPS transient was revised to include the mass addition of the PD i
charging pump and resulted in a calculated peak pre.ssure of 474 psig.
I PSE&G Incident Report (IR)94-419, dated November 17, 1994, documented this latest discovery and concluded that the Unit 1 POPS no longer met its design basis single failure criterion because a single PORV could no longer mitigate the transient.
PSE&G reported this to the NRC under 10 CFR 50.72 as an unanalyzed condition for Salem Unit 1.
IR 94-419 provided justification for the continued operation of Unit 1 based on RHR relief valve RH3 being available to augment POPS. With the three valves (two PORVs and RH3) available below 312"F, sufficient relief capacity was reasoned (by the licensee) to be provioed and the single failure criterion could be met.
However, the licensee considered Unit 2 to be "not reportable" because with a single PORV the peak transient pressure was still 1.0 psi below its P/T curve limit.
i The inspector concluded that, since the margins to safety for overpressure protection (viz, peak pressure versus Appendix G P/T limits) had either been significantly reduced or lost altogether (depending upon which transient and assumptions are adopted as limiting), the new " limiting" transient represented a potential unreviewed safety question.
r---
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4 1
h 6
i RCS Vent Path l
TS for both Salem units require cold overpressure protection be provided by l
either the redundant PORVs (the POPS system) or a reactor coolant system vent of greater than or equal to 3.14 square inches (in'). Venting the RCS is an alternative to having the POPS operable and would be accomplished after depressurizing the RCS. The TS action statement for POPS requires that, in the event a PORV fails and cannot be restored within seven days, the reactor must be depressurized and vented through the 3.14 in' vent within the next eight hours.
The inspector could find no specific justification for the TS-required vent area of 3.14 in'.
However, the inspector concluded that the vent area required in TS should be adequate based on:
(1) the flow from an unrestricted opening of 3.14 in' would encounter less resistance than that through a single PORV; (2) a single PORV must be shown to provide sufficient relief capability -
i even with its delay for actuation; and (3) the vent area is passive protection and, therefore, does not need to be redundant. The inspector noted that while no formal analyses were available to support the 3.14 in' area or compare it to actual PORV capacity, the full-open port area of a single PORV is approximately 2.2 in'.
The " equivalent throat area" (a term used by Westinghouse in WCAP-ll640, March 1988) of a full-open PORV would be adjusted for hydraulic resistance, and factors affecting this correlation were provided in a December 8,1992, memorandum to PSE&G from the valve vendor, Copes Vulcan. The vendor's memorandum depicts the estimated flow coefficient as a function of valve lift or opening during its 1.5-second stroke. The Sales PORVs are 2-inch diameter Model D-100 " plug-in-cage" valves, with flow coefficients on the order of 50. This flow coefficient can be used, along with previously compiled EPRI test data for these type valves, to calculate a so-called equivalent area-corresponding to a smoothly convergent nonflashing (sonic flow) nozzle - that licensee thermal hydraulic engineers estimated to be 1.21 in'.
The RCS vent area of 3.14 in', by itself, has no hydraulic meaning unless a j
J geometry can be assumed so that resistance and loss factors can be calculated.
Nonetheless, a single PORV gagged-open is clearly enveloped in the RCS vent configuration by a simple two-inch diameter flanged opening w'. hen corrected for flow losses; this effective area is on the order of 2-2.5 in The licensee, in fact, utilizes several optbns to establish the RCS. vent including removal of a steam generator primary-side manway, removal of one or more code safety valves, or gagging-open the PORV's as an alternative to POPS valves set to automatically relieve at 375 psig.
Code Case Anoroval The inspector reviewed the licensee's documentation and interviewed personnel involved with the POPS issue during the 20 months between the NSAL issuance in March 1993 and PSE&G's 50.72 notification in November 1994. The inspector concluded that there was an adequate assurance of safety, based on the additional relief capacity of valve RH3 and the margin that can be gained with use of ASME Code Case N-514. Based on the inspector's discussions (prior to February 1995) with representatives from the NRC Office of Nuclear Reactor
l i
l Regulation (NRR), ASME Code Case N-514 represented a technically acceptable position, although a plant specific exemption would be required.
On December 16, 1994, a conference call betwaen PSE&G and NRC representatives was held to discuss the licensee's more immediate actions to resolve certain aspects of the POPS issue. During this call, the licensee committed to limit i
the number of RCPs in service (per existing procedures) when RCS temperature l
is below 200*F, and to maintain procedural controls preventing an intermediate head safety injection pump from injecting into the RCS. These commitments l
were formally submitted in a letter to the NRC from PSE&G issued later that l
same day.
j On December 22. 1994, PSE&G submitted an application for NRC approval of ASME Code Case N-514.
Included in the submittal were the calculations supporting the new design-basis transient for POPS. Without the code case, PSE&G credited valve RH3 on Unit I to meet the design basis single failure criterion for POPS. However, for Unit 2, the licensee did not credit valve RH3 because the peak pressure, based on a single PORV, was predicted to be 1.0 psi below the unit's P/T limit. By letter dated February 13, 1995, the NRC issued an exemption from the requirements of 10 CFR 50.60 for Salem Units I and 2.
This exemption permits using the safety margins recommended in ASME Code Case N-514 j
in lieu of the safety margins required by Appendix G to 10 CFR 50. Therefore, 1
j each unit's P/T curve limits for POPS were increased by 10%; the Unit I and 2
=
limits became 495 and 522 psig, respectively.
3.0 CONCLUSION
S i
The inspector considered several aspects of PSE&G's actions to resolve the POPS issue over the past'20 months as inadequate or inappropriate:
The POPS issue was initially dispositioned to show that the requirements of i
e 10 CFR 50.60 were met, invoking an ASME code case that had not received prior NRC approval.
When inclusion of the setpoint nonconservatism put the Sales Units outside e
the POPS design basis, reports to the NRC were not made pursuant to 10 CFR i
50.72 and 73.
No safety evaluation pursuant to 10 CFR 50.59 was performed prior to e
revising the POPS design-basis transient (described in the Salem FSAR) in September 1994. As of the December 19, 1994, exit meeting, a 50.59 evaluation had not been completed. Several times during the licensee's attempts to resolve the POPS questions, the margins to safety for POPS (defined in the February 1980 NRC safety evaluation) were found to be reduced, but not appropriately evaluated.
It took almost two years (March 1993 to February 1995) for PSE&G to take The lowest appropriate actions to address the NSAL nonconservatism.
priority possible was assigned to this issue within the Operational Experience Feedback program in March 1993, and the issue was not entered into an appropriate PSE&G quality program for resolving engineering l
discrepancies for over a year.
~-.
,s.
i 1
8 The adequacy of the new design basis for POPS is currently under review by the
[
NRC's Office of Nuclear Reactor Regulation. Pending NRC assessment of the i
licensee's proposed limiting design-basis transient for POPS, this issue is unresolved.
(URI 50-272;311/94-32-05)
The licensee's:
(1) reliance on ASME Code Case N-514 without NRC approval, (2) failure to report a condition outside the Sales design basis, and (3) failure to perfom an adequate safety evaluation of the revised POPS design-basis transient are all apparent violations of NRC requirements.
Further, the process used to address the issue (memorandum superseding memorandum) was considered to be fragmented and not appropriate for potentially safety-significant issues. The inspector further concluded that the corrective action processes that were engaged (a year late) did not appropriately resolve a condition outside the plant's design basis.
l 4.0 MANAGEMENT MEETINGS 1
l Licensee representatives were informed of the scope and purpose of this inspection at an entrance meeting conducted on December 5, 1994. Findings i
were periodically discussed with the licensee throughout the course of this inspection. A telephone conference call was conducted between NRC and PSE&G representatives on December 16, 1994, to discuss the licensee's plans to j
resolve several aspects of the POPS issue. During this call, PSE&G committed to taking several actions and subsequently documented these commitments in a i
letter to the NRC issued later that day.
The inspector met with the principals listed below to summarize preliminary findings on December 19, 1994. The licensee acknowledged the preliminary findings and conclusions, with no exceptions taken. Further, the bases for i
the preliminary conclusions did not involve proprietary information, nor was j
any such information expected to be included as part of the written inspection report.
Public Service Electric & Gas Comoany L. Catalfomo Operations Manager J. Morrison Salem Technical Department Manager M. Morroni Controls Maintenance Manager J. Ranalli Nuclear Mechanical Engineering Manager D. Smith Principal Engineer, Nuclear Licensing J. Summers General Manager, Salem Operations Manager EC C. Marschall Senior Resident Inspector, Salem D. Hoy Reactor Engineer, DRS J. White Chief, RPS2A, DRP
h 1
9 A final summary was provided to PSE&G representatives by telephone on March 23, 1995, discussing the results of the NRC inspection and evaluation I
that took place after the December 1994 site visit. Another telephone conversation was held on March 29., 1995, to discuss the issue of PORV flow l
characteristic's (refer to page 6, "RCS Vent Path") between E. Kelly of the i
NRC and the following PSE&G representatives:
C. Lambert Manager, Nuclear Engineering Design l
Vijay Chandra Technical Consultant, Thermal Hydraulics Gita Narasimhan Mechanical Engineer Mahesh Danak Mechanical Engineer i
)
1 I
17
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7.0 EXIT INTERVIEWS / MEETINGS 7.1 Resident Exit Meeting The inspectors met with Mr. J. Sumers and other PSE&G personnel periodically and at the end of the inspection report period to sumarize the scope and findings of their inspection activities.
j Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.
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ATTACHMENT 3 April 7, 1995 i
EM 95-62 l
Mr. Leon R. Eliason i
Chief Nuclear Officer & President Nuclear Business Unit Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
NRC INSPECTION NOS. 50-272/95-02; 50-311/95-02 l
Dear Mr. Eliason:
The enclosed report documents an inspection for public health and safety, conducted by Mr. C. Marschall, Senior Resident Inspector and other members of the NRC resident and regional staff at the Salem Nuclear Generating Station for the period between January 29, 1995 and March 22, 1995. The inspectors discussed the findings of this inspection with Mr. J. Summers, General Manager-Salem Operations, and other members of your staff.
Within the scope of this inspection, relative to Salem Unit 2, the inspectors identified several examples of continued weaknesses relative to corrective action determination and effectiveness, and an example of inadequate measures to assure proper configuration control for a safety-related system following modification of pressurizer safety valve loop seals. As a result, the Unit was operated outside the design basis for an entire operating cycle. These apparent violations, as described in Enclosure 1, are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy),10 CFR Part 2, Appendix C.
Accordingly, a Notice of Violation is not being issued for these inspection findings at this time. The number and characterization of the apparent violations may change as a result.of further NRC review.
Accordingly, no response to these matters is required at this time.
Additionally, we consider a violation concerning failure to collect grab samples of the waste gas decay tank a non-cited issue since the item conforms with our enforcement policy as described in 10 CFR Part 2, Appendix C, Section-Vll. The details of all of these matters are described in the enclosed inspection report.
These apparent violations (as described in the enclosure) were discussed between Mr. John Sumers, General Manager, Salem Operations and Mr. John White of our office on April 7,1995. An Enforcement Conference will be scheduled with your organization in the near future. This conference will be closed to l
public observation.
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%Y ggout
1 I
Mr. Leon R. Eliason 2
The decision to hold an Enforcement Conference does not mean that violations have occurred, or that enforcement action will be taken. The purposes of this conference are: (1) to discuss the apparent violations, including cause and safety significance; (2) to provide you with an opportunity to point out errors in our inspection report, and identify corrective actions, taken or planned; and (3) to discuss any other information that will help us determine the appropriate action in accordance with the Enforcement Policy. The conference is also an opportunity for you to provide any information j
concerning your perspectives on the severity of the apparent violations, and the application of the factors that the NRC considers when it determines the amount of a civil penalty that may be assessed in accordance with Section i
i VI.B.2 of the Enforcement Policy.
Your cooperation with us is appreciated.
Sincerely, ORIGINAL SIGNED BY WAYNE LANNING FOR:
Richard W. Cooper, Director Division of Reactor Projects Docket Nos.
50-272; 50-311
Enclosures:
1.
Apparent Violations 2.
NRC Inspection Report Nos. 50-272/95-02; 50-311/95-02 cc w/ encl:
J. J. Hagan, Vice President-0perations S. LaBruna, Vice President - Engineering and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
P. J. Curham, Manager, Joint Generation Department, Atlantic Electric Company R. Burricelli, General Manager - Information Systems & External Affairs J. Summers, General Manager-Salem Operations J. Benjamin, Director of Quality Assurance and Safety Review F. Thomson, Manager - Licensing and Regulation R. Kankus, Joint Owner Affairs A. C. Tapert, Program Administrator R. Fryling, Jr., Esquire M. J. Wetterhahn, Esquire Consumer Advocate, Office of Consumer Advocate William Conklin, Public Safety Consultant, Lower Alloways Creek Township Public Service Commission of Maryland D. Screnci, PA0 (2)
Nuclear Safety Information Center (NSIC)
NRC Resident Inspector State of New Jersey State of Delaware
i r
Mr. Leon R. Eliason 3
4 Distribution w/ enc 1-l Region I_ Docket Room (with concurrences) i K. Gallagher E. Kelly, DRS (section 4.6 and 4.8)
?UBLIC Distribution w/ encl: (Via E-Mail)
.L. Olshr.n, NRR W. Dean, OEDO J. Stolz, PDI-2, NRR i
M. Callahan, OCA Inspection. Program Branch, NRR (IPAS)
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DOCUMENT NAME:
9502. sal T.
i a espy w mis so.wn n. means m em nec v - copy =thout en.ohment/.rmio.ur. T - copy wem
.n. chm.nt/.nolosur. W = No copy l NAME Cu~sch it JWhim
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lDATE 4/ /95 4/ /95 4/ /95 OFFICIAL RECORD COPY l
i ENCLOSURE 1 i
APPARENT VIOLATIONS i
A.
10 CFR 50 Appendix B Criterion V, " Instructions, Procedures, and Drawings", requires that measures to ensure activities affecting safety are satisfactorily accomplished. The following example of a failure to meet this requirement occurred in May 1993:
~
During a modification to install a drain system for the Salem Unit 2 pressurizer code safety loop seals, the licensee did not adequately ensure that the drain valves were properly positioned prior to plant startup after the modification.
Specifically, valve 2PR66, a valve in a common drain line for the 2PR3, 2PR4, and 2 PRS, pressurizer safety valves, was left closed throughout the operating cycle between May 1993 and October 1994. As a result, the licensee operated Salem Unit 2 in that period with the loop seals filled with water. No analysis was performed to assess the effect of filled loop seals on the discharge i
piping or on system operability.
Subsequently, in an effort to demonstrate that thrust loading from the water in the loop seals would not damage safety valve discharge piping sufficiently to prevent the pressurizer code safety valves from limiting Reactor Coolant System i
pressure, the licensee initiated a detailed engineering calculation, scheduled for completion in April 1995.
B.
10 CFR 50, Appendix B, Criterion XVI " Corrective Action", requires in part, that licensees identify significant conditions adverse to quality, determine their causes, and take corrective action to preclude recurrence. Three examples of failure to meet this requirement occurred:
1)
On June 7,1994, the licensee identified that material management documentation for limit switches related to the reactor head vent valves, improperly classified the components as non-safety related. A nuclear design discrepancy evaluation form (DEF) identified that a switch short circuit could render two head vent valves inoperable since the components were powered from the same common circuit. Notwithstanding, the DEF did not identify any concern relative to operability or safety.
The reviewers determined that switches obtained as safety-related or non-safety related were essentially the same part, with the exception that the qualified part is certified by testing.
It was not until February 1995, that the licensee determined that non-safety related limit switches were installed in reactor head vent valves IRC41 and IRC43 at Salem Unit 1.
Subsequently, the licensee failed to perform and document an engineering evaluation to demonstrate the acceptability of continued Salem Unit 1 operation with non-safety-related parts installed in a safety-related application.
2)
On February 24, 1995, at 8:58 p.m. Unit No. 1 operators placed control of a Power Operated Relief Valve (PORV) in the manual mode, rendering it inoperable, and failed to adhere to the
2
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Technical Specification 3.4.3 action statement which required operators to close the block valve within one hour. A shift supervisor discovered the error and corrected it on February 25, 1995 at 7:10 p.m. (about 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> later). TW
-formance error is similar to a violation of the same technica. specification requirement involving on Salem Unit No. 2_ on March 24, 1994. The licensee's corrective actions for the previous occt:rrence appear to have been ineffective in preventing recurrence of this type of performance deficiency.
3)
On July 6,1994, safety-related reactor head vent valve 2RC40 failed to operate (stroke open) during testing while Unit No. 2 was in cold shutdown. Subsequently, the licensee speculated that the low reactor coolant system temperature which may have promoted boric acid crystallization that adversely affected valve operation, and later confirmed function of the valve when RCS temperature was increased.
Subsequently, the valve was returned to normal service on July 10, 1994, without any review or assessment in accordance with established procedures.
In this case, the licensee failed to process this occurrence in accordance with the applicable " Work Control Process" procedure.
Consequently, this failure of a safety-related component was never documented and formally assessed relative to preventive maintenance, operability, actions to prevent recurrence, or generic implications.
U. S. NUCLEAR REGULATORY COMMISSION REGION I Report Nos.
50-272/95-02 50-311/95-02 t
License Nos.
DPR-70 DPR-75 Licensee:
Public Service Electric and Gas Company-P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facility:
Salem Nuclear Generating Station Dates:
January 29, 1995 - March 22, 1995 Inspectors:
C. S. Marschall, Senior Resident Inspector J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector ORIGINAL SIGNED BY:
4/7/95 John R. White, Chief Reactor Projects Section 2A Date 0
Insoection Summary:
This inspection report documents inspections to assure public health and safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security, engineering, technical support, safety assessment and quality verification. A violation involving measures to assure configuration control, and several examples of deficient corrective action were identified in this period.
Amplification is contained in the Executive Summary.
i
EXECUTIVE
SUMMARY
Salem Inspection Reports 50-272/95-02; 50-311/95-02 January 29, 1995 - March 22, 1995 OPERATIONS (Module 71707) The licensee performed a safe post-refueling reactor startup for Salem Unit 2. - Subsequently, operations performed a safe 3
shutdown of the Salem units to effect repair of inoperable solid state l
protection system power supplies.
l l
The inspectors noted increased management awareness and involvement in the daily operation of the Salem units. Notwithstanding, the inspector identified l
two missed opportunities for consideration of the risk associated with the l
concurrent work on safety-related equipment.
On February 24, 1995, Salem Unit 1 operators failed to comply with the Technical Specification 3.4.3 action statement requirements for an inoperable l
Power Operated Relief Valve (PORV). The inspectors noted that the matter was repetitive relative to a previous situation on March 24, 1994, when operators l
also failed to comply with Technical Specification requirements for an inoperable Salem Unit 2 PORV. Consequently, corrective action effectiveness l
l is considered a continuing weakness. This most recent finding constitutes an l
apparent violation of 10 CFR 50, Appendix B requirements pertaining to
[
correction action.
MAINTENANCE and SURVEILLANCE (Modules 61726,62703) Operations, Maintenance, Planning, and Radiation Protection demonstrated good coordination, thorough attention to detail, and excellent radiation worker practices in completing t
l the No. 21 reactor coolant pump maintenance activities.
i I
A PSE&G team, assembled to identify the cause of control problems with main steam atmospheric relief valves (MS10s), performed a very thorough root cause analysis. The inspectors noted, however, that the team's efforts occurred only after a long history of continuing and repetitive problems with MS10 f
control at the Salem units.
I Inspectors determined that the licensee adequately and conservatively implemented the Technical Specification 4.6.1.5 requirement for surveillance l
of containment air temperatures.
f ENGINEERING and TECHNICAL SUPPORT (Modules 37551,71707,92903) Reactor engineering performed a well documented, technically sound, comprehensive, and timely evaluation of a Unit I radial flux tilt.
Reactor engineering's i
technical expertise and support of operations contributed to safe plant
~
performance.
Engineering could not determine a root cause for recurring spurious alarms and i
test faults affecting the Safeguard Equipment Control system; however, l.
engineering did aggressively pursue suspected electromagnetic interference i
ii-i i
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-(EMI) or electrical noise as a possible cause, and is continuing to actively monitor and diagnose system performance.
The inspectors identified several minor scaffolding discrepancies with no safety significance, but. noted that a potential exists to adversely affect safety through ineffective control of scaffolding.
Inspectors identified that failure to ensure pressurizer safety valve loop l
seal drains were properly installed and functioned effectively is an apparent l
violation of the 10CFR50, Appendix B, Criterion V, which specifies that l
activities affecting safety are properly accomplished.
j Continuing weakness with corrective action effectiveness was identified.
relative to control of materials installed in safety-related reactor head vent valves, and failure to establish corrective measures in response to mis-
-operation of head vent 2RC40. These items were identified as examples of an l
apparent violation of 10CFR50,. Appendix B, Criterion XVI, " Corrective Action".
j The inspector determined that the licensee had taken appropriate measures to address reactor head leakage in response to Generic Letter 88-05.
PLANT SUPPORT (Module 71707,71750) Licensee Event Report 94-15 identified that operators failed to collect grab samples of the Waste Gas Decay Tank as required by Technical Specifications when the gaseous effluent monitoring instrumentation was determined to be out of service. Though, technically a violation of regulatory requirements, enforcement discretion was applied in i
accordance'with NRC policy; and the item is considered as a non-cited violation.
The licensee acted properly relative to Emergency Classification notification l
in response to an Unusual Event due to low river water level that had the i
potential to affect circulating water and service water systems.
j SELF-ASSESSMENT.AND QUALITY VERIFICATION Notwithstanding the violations identified in this report, PSE&G generally l
operated the Salem units safely. However, the continued manifestation of-recurring equipment problems and ineffective corrective action indicate that PSE&G has not yet achieved any significant' improvement in overall performance.
The' licensee's failure to implement measures (procedures, directions, or i
drawings) to assure proper configuration following the. safety relief valve i
loop seal modification during 2R7 demonstrates weakness in work controls.
l The response to the recurring problems with the main steam atmospheric relief i
valves (MS-los) demonstrated recurrence of previously documented weak initial i
root cause investigation. As has also been the case in the past, in response to NRC questions and management recognition of the impact of the MS-10 problems, the licensee commissioned a multi-disciplinary team to perform a
(
comprehensive engineering investigation of the cause of continued MS10 reliability problems. While such effort is considered a positive step in attempting to resolve this long-standing issue, the licensee supposed that this item was previously resolved as a result of troubleshooting and i
engineering efforts following the April 7, 1994 trip.
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TABLE OF CONTENTS j
EXECUTIVE
SUMMARY
11
{
TA8LE OF CONTENTS............................
iv l.0
SUMMARY
OF OPERATIONS.......................
1 l
I 2
l 2.0 OPERATIONS 2.1 Solid State Protection System Forced Shutdown........
3 l
2.2 Risk Management.......................
3 l
2.3 Failure to Comply with Technical Specification Action Statement..........................
4 3.0 MAINTENANCE AND SURVEILLANCE 4
3.1 MAINTENANCE.........................
4 3.1.1 Reactor Coolant Pump Seal Replacement.........
5 3.1.2 Main Steam Atmospheric Relief Valves 6
6 3.2 SURVEILLANCE 3.2.1 Containment Average Air Temperature..........
7 i
4.0 ENGINEERING............................
8 4.1 Salem Unit 1 Radial Flux Tilt Evaluation 8
4.2 Scaffolding in Safety-Related Areas.............
8 4.3 Safeguard Equipment Control (SEC) Troubleshooting......
9 4.4 Pressurizer Code Safety Valve Loop Seals 9
4.5 Control of Reactor Head Vent Material, Parts, and 11 Components 4.6 Reactor Head Vent Valves 13 4.7 Review of Enforcement Discretion Requests..........
14 4.8 Reactor Head Leakage Detection System............
15 i
5.0 PLANT SUPPORT...........................
16 5.1 Radiological Control s....................
16 5.1.1 Failure to Sample Waste Gas Decay Tank (WGDT) on 16 Unit 2 16 5.2 Emergency Preparedness 5.2.1 Unusual Event Due to Low Water Level 17 17 6.0 REVIEW 0F REPORTS AND OPEN ITEMS 18 7.0 EXIT INTERVIEWS / MEETINGS 7.1 Resident Exit Meeting....................
18 I
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iv
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L DETAILS 1.0
SUMMARY
OF OPERATIONS Unit 1 began the period operating at 100% power. On February 3, the licensee l
initiated a shutdown to comply with plant Technical Specification requirements for inoperable solid state protection systems (SSPS). On February 4, the licensee entered Mode 5 (Cold Shutdown). On February 15, after completing modifications to SSPS, operators entered Mode 4 (Hot Shutdown). The licensee maintained the unit in Mode 4 while resolving problems encountered with main i
I steam atmospheric relief valves (MS-10s). On February 27, operators commenced a reactor startup, and on March 2, they increased power to 48%. On March 3, operators reduced power to 28% for a bioshield entry to adjust RCP oil levels.
On March 8, operators increased power to 100% and maintained the unit there until March 18, when operators reduced power to 70% in response to marsh grass fires with the potential to effect offsite power lines. Operators returned the unit to 100% power on March 19. The unit continued to operate at 100%
power until March 20, when power was reduced to 94%, due to a leak in the No.
11C feedwater heater.
Power remained at 94% through the end of the inspection period.
Unit 2 began the period in Mode 3 (Hot Standby). On February 1, the licensee commenced and safely completed a reactor startup. On February 3, the ficensee comer.nced a Technical Specification required shutdown from 1% power, for inorerable SSPS power supplies. The licensee placed the unit in Mode 5, corspleted modifications to SSPS, and commenced a plant startup. On February 11, operators took the reactor critical and commenced power escalation. On r bruary 19, the licensee decided to shutdown the unit (then at 47% power) to e
remove No. 21 reactor coolant pump (RCP) from service due to low seal water leakoff flow. The licensee placed the plant in Mode 5, replaced the No. I seal, and commenced a plant startup. On March 8, operators achieved reactor criticality and commenced power escalation. The unit operated at 90% power l
until March 18, when operators reduced power to 80% in response to marsh grass i
fires with the potential to affect offsite power lines.
During the power reduction, operators encountered problems with manual control of No. 22 main feedwater pump, and further reduced power to 50% for repair of the pump l
controls. Operators returned the unit to 97% power on March 20. On March 22, operators reduced Unit 2 to 50% power in response to speed oscillations in the No. 21 main feedwater pump.
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2.0 OPERATIONS The inspectors verified that Public Service Electric and Gas (PSE&G) generally operated the facilities safely and in conformance with regulatory requirements except as noted in the details of this report. The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews anc' discussions with personnel, independent 1
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2 verification of safety system status and Technical Specification compliance,
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and review of facility records. The inspectors performed normal and back-shift inspections, including 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> of deep back-shift inspections.
2.1 solid State Protection System Forced Shutdown At 10:30 p.m. on February 1,1995, the licensee declared the solid state protection system (SSPS) for both units inoperable, since a steam line break in the turbine building could cause the complete loss of the SSPS. Operators entered Technical Specification 3.0.3 for both units and began a shutdown of l
Unit I at 15 percent per hour. Operators maintained Unit 2 in Mode 2 r
(Startup) with the main steam isolation valves (MSIVs) shut.
j The licensee determined that a steam line break could cause wiring to the f
turbine stop valves, the auto-stop oil pressure switches, and the reactor i
coolant pump (RCP) breaker position indication to short circuit. The short circuit would de-energize the 15 volt and 48 volt SSPS power supplies causing j
a reactor trip, and rendering both SSPS channels incapable of generating an i
automatic safety injection actuation.
At 2:30 a.m. on February 2, the NRC granted the licensee enforcement discretion for 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to allow the licensee to modify the SSPS. Operators terminated the shutdown on Unit I and returned power to 100Y. Salem planned to correct the inadequate electrical separation.
In addition, the licensee established compensatory measures, including operator training on manual actuation of safety injection, a moratorium on engineered safety feature (ESF) equipment maintenance until modification completion, maintaining Unit 1 in steady state conditions, and maintaining Unit 2 in Mode 2 with the MSIVs closed.
At 5:22 a.m. on February 3, technicians de-energized a 15 volt power supply for Unit 1 SSPS train "A" to perform planned modifications. However, the redundant train "A" power supply simultaneously.t; hoed and caused the loss of SSPS train "A".
The licensee stopped the modific M n and restored train "A" to normal. The licensee could not identify the rooc cause failure of the 15.
volt power supply within the technical specification (TS) allowed outage time.
At 11:00 a.m. on February 3, the licensee initiated a Unit I shutdown from 100f, power to comply with TS 3.3.1.1. At 4:30 p.m. on February 3, the NRC rescinded the enforcement discretion for both units based upon the complications imposed by SSPS power supply failures. At 10:30 p.m. on February 4, operators placed Unit 1 in Mode 5 (Cold Shutdown). At 4:31 a.m.
on February 5, operators placed Unit 2 in Mode 5.
The inspector observed that operations performed a safe shutdown of Salem Unit 1.
Refer to NRC Inspection Report 50-272 and 50-311/95-03 for additional assessment of assessment of the SSPS modification and associated activities.
2.2 Risk Management 4
i During the inspection period, the inspector identified two missed licensee opportunities to consider tne risk associated with the concurrent performance i
of work on multiple pieces of safety-related equipment. Specifically, on
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3 March 7, 1995, Unit 1 operators commenced a turbine driven auxiliary feedwater (TDAFW) pump surveillance prior to returning No. 12 residual heat removal i
(RHR) pump to service. The No. 12 RHR pump was out of service for 1reventative maintenance and was returned to service shortly after operators agan the TDAFW pump surveillance. On March 9, 1995, operators authorized i
sandblasting immediately adjacent to No. 21 service water pump while No. 23 l
service water pump tagged out for maintenance. The inspector considered that the sandblasting and associated scaffolding had the potential to adversely l
affect No. 21 service water pump operability due to close proximity to interferences and grit at a time when No. 23 service water pump was not i
available for use, i
The inspector discussed the risk perspective with the operators. As a result, the aggregate risk was re-considered and activities that had the potential to directly affect the operability of No. 21 service water pump were curtailed until No. 23 service water pump was returned.
2.3 Failure to Comply with Technical Specification Action Statement j
At 8:58 p.m. on February 24, with Salem Unit 1 in mode 3, an operator placed pressurizer Power Operated Relief Valve (PORV) IPR 2 in manual as required by procedure S1.lC-CC.RC-0082, IPC-455K Pressurizer Pressure Control. Contro1 room operators noted in the logs that they had entered Technical Specification 3.4.3, Action A, however, they did not close block valve IPR 7 within one hour.
Salem Unit 1 Technical Specification.3.4.3 Action A requires, in part, that.in 1
modes 1, 2 and 3, with one or more power PORVs inoperable, within one hour either restore the PORV to operable status or close the associated block valves. At 7:10 p.m. on February 25, the Salerr Unit 1 Nuclear Shift Supervisor realized that the PORV was in manual and immediately instructed the operator at the controls to close block valve IPR 7.
The inspectors noted that the NRC previously identified a similar failure to adhere to Technical Specification 3.4.3 on March 25, 1994, involving Unit 2.
The corrective actions initiated for that instance appeared not to have be sufficient to prevent recurrence of this type of violation. Consequently, this latest example constitutes apparent non-conformt.nce with the requirements of 10 CFR 50, Appendix B, Criterion XVI, which requires that measures be established to assure that corrective action is taken to preclude recurrence of significant conditions adverse to quality (EEI 50-272;311/95-02-01).
3.0 MAINTENANCE AND SURVEILLANCE 3.1 MAINTENANCE The inspectors observed portions of the following safety-related maintenance to verify-that the licensee conducted the activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.
4 The inspector observed portions of the following activities:
Work Order (WO) or Design Unil Chanae Packaae (DCP)
Descriotfog Salem 1 WO 950213241 12SJ134 - Safety Injection Pump to Cold Legs Valves Salem 1 WO 951126030 12 Service water pump strainer repair Salem 1 WO 950216203 Safety injection pump breaker repair Salem 2 WO 941226085 23 Charging pump The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance program.
3.1.1 Reactor Coolant Pump Seal Replacement On February 19, Salem Unit 2 control room operators shut the plant down from 47% power to remove N3. 21 reactor coolant pump (RCP) from service due to low seal water leakoff flow. Licensee attempts to identify and correct the low flow condition while in Mode 3 (Hot Standby) were unsuccessful. On February 22, operators placed the unit in Mode 5 (Cold Shutdown) to perform a RCP seal inspection.
i On February 23, the licensee placed the No. 21 RCP on the " backseat" to allow for seal inspection or replacement without operating at reduced RCS inventory.
Technicians found a small amount of debris in the No. I seal and an out of specification runout on the No. I runner retainer sleeve. On March 1, the licensee completed replacement of the No. I seal package and the retainer sleeve. At the end of the report period, the licensee had not completed an in-depth evaluation of the No. I seal and sleeve.
The inspectors noted that plant staff safely performed the RCP "backseating" process. Operations, maintenance, planning, and radiation protection demonstrated good coordination, thorough attention to detail, and excellent radiation work practices in completing the No. 21 RCP maintenance activities.
The inspector noted that No. 21 RCP low seal water flow was also a concern following the Salem Unit 2 seventh refueling outage in May 1993. The licensee reduced pressure (< 1000 psig) to reseat / flush the seal at that time.
Although seal return flow improved (> 1.0 gpm), operators noted low flow alarms in October 1993 (believed to be a spurious alarm coincident with component cooling water temperature manipulations), in April 1994 (instrumentation problem with corrective action scheduled for 2R8), and in The October 1994 (related to component cooling water temperature variations).
No. 21 RCP seal was originally scheduled for inspection during the recently completed refueling outage; however, emergent concerns with the No. 22 RCP seal assembly caused the licensee to redirect those resources. The inspector
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observed that while the licensee eagerly pursued the low seal water return flow problem when flow dropped below 1.0 gpm, the degraded condition existed since May 1993. Although the low seal flow did not present immediate safety concerns, the inspector concluded that the licensee did not perform timely or thorough root cause determination and corrective action. As a result, an unresolved equipment deficiency required operators to shut the plant down for i
seal repair.
3.1.2 Main Steam Atmospheric Relief Valves On February 3, with atmospheric steam relief valve 13M510 in automatic, a Salem Unit 1 operator attempted to close the valve by increasing the pressure setpoint of the controller. The valve responded erratically to the operator actions, then apparently shifted to manual control without operator action and failed open. After changing the pushbutton module, the operator was able to close the valve. On February 11, a Salem Unit 2 operator found that the 22MS10 controller did not properly track pressure.
In addition, the controller did not properly demand valve opening in response to operator actions. On February 17, 13MS10 failed open again.
The inspectors noted that, although the licensee was initially slow to assemble the resources to evaluate the cause of the MS10 valve control problems, they eventually mounted a multi-disciplinary team to examine the recent problems with 13MS10 and 22MS10. The team found maintenance, design, and refurbishment inadequacies caused the initial 13MS10 failure. These processes contributed to less than optimal calibrations, installation of incorrect parts (K3 relays), and inadequate preventive maintenance to preclude capacitor failures. The team found that the 22MS10 failure resulted from calibration problems, and servo-station sensitivity that was not recognized or considered during modifications. The 13MS10 problem on February 17 resulted from low input impedance test equipment providing a parallel path for current flow.
The inspectors concluded that the team performed very thorough root cause analysis. The inspectors noted, however, that the team's efforts occurred only after a long history of problems with MS10 controller deficiencies at the Salem units, that had supposedly been corrected and resolved previously. The implication of these latest findings support previous assessments of weak and ineffective root cause and corrective action programs that continue to affect Salem operations.
3.2 SURVEIU.ANCE The inspectors performed detailed technical procedure reviews, observed surveillances, and reviewed completed surveillance packages. The inspectors verified that plant staff did the surveillance tests in accordance with approved procedures, Technical Specifications and NRC regulations.
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The inspector reviewed the following surveillances:
Mail Procedure NL Igit Salem 1 S1.0P-PT.TRB-0001 Turbine Auto Trip Mechanisms Oper.cional Test i
i Salem 1 S1.0P-ST.CS-0001 Innrvice Testing - 11 Coistainment Spray Pump Salem 1 S1.0P-ST.MS-0003 Steam Line Isolation and Response Time Testing Salem 1 S1.0P-ST.RC-0008 Reactor Coolant System Water Inventory Balance Salem 1 SI.RE-ST.ZZ-0002 Shutdown Margin Calculation Salem 2 52.IC-ST. SSP-0008 Solid State Protection System l
Train A Functional Test The inspectors observed that plant staff did the surveillances safely, effectively proving operability of the associated systems.
1 3.2.1 Containment Average Air Temperature Each Salem unit has 10 containment air temperature monitoring points.
Salem Technical Specification (TS) 4.6.1.5 requires that the containment average air temperature be the arithmetical average of the temperatures at any five of the ten listed locations. The Salem plant computer averages all ten locations.
The inspector also noted that one of the ten plant computer inputs for Unit 1 was taken at elevation 136' northeast vice elevation 78'-northeast as listed
.in TS 4.6.1.5.
The licensee noted that the Westinghouse Standard Technical Specification lists five measurement points for this surveillance, and requires that the containment average air temperature is determined from the arithmetic average of these five points. The licensee concluded that the use of all ten measurement points, as opposed to any five of the ten,.results in a more accurate determination of overall containment average air temperature. The licensee considered the input from Unit 1 elevation 136' a more conservative temperature than elevation 78'.
In 1992, licensing developed a proposal (never submitted to the NRC) to change TS 4.6.1.5 to require the arithmetic average of the temperatures from at least five of the ten locations. The proposal included removing the list of the monitoring locations from TS and placing it in the updated Final Safety Analysis Report (UFSAR). The licensee never submitted the proposed change to the NRC.
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The inspector reviewed the licensee's implementation of TS Surveillance 4.6.1.5 and determined that averaging the ten temperatures represented a more
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conservative indication of containment temperature than required.
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Notwithstanding, the licensee initiated an Incident Report, changed the l
surveillance to require averaging five temperatures, and initiated a review to assess the need to change TS 4.6.1.5.
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4.0 ENGINEERING 4.1 Salem Unit 1 Radial Flux Tilt Evaluation j
On March 4,1995, Salem Unit 1 operators increased power to 48%. Operators performed 51.0P-ST.NIS-0002, Power Ofstribution - Quadrant Power Tilt Ratio, and calculated a quadrant power tilt-ratio (QPTR) of approximately 1.03. The i
QPTR is the ratio of the maximum upper and lower excore detector calibrated j
output to' the average of-the upper and lower excore detector calibrated outputs. Technical Specification 3.2.4 requires QPTR to be less than 1.02 before proceeding above 50% power.
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1 Reactor engineering obtained a flux map and determined the QPTR, based on l
incore detectors, to_be 0.8% (compared to the 3% tilt calculated from excore detectors). Reactor engineering analyzed this flux map and determined that i
the flux tilt was not abnormal. Reactor engineering attributed flux tilts to the previous full power core conditions, and expected quadrant tilts to return j
to the previous hot full power values following power escalation. Reactor engineering recommended updating the nuclear instrumentation, calculating the t
l QPTR once per hour, limiting the power increase to 3% per hour, and performing additional flux maps at 75% and 95% power.
In addition, reactor engineerirg r
requested Westinghouse to perform a core design evaluation of the cycle 12 i
flux maps. On March 6, Westinghouse determined that the safety analysis limits were expected to be met during the planned power escalation.
l Westinghouse concurred with PSE&G's expectations that the incore tilt would return to previous full power values. On March 8,' the plant reached full j.
l power and operators noted a shift in the flux tilt back to previous full power l
values. Operations performed QPTR's hourly and consistently calculated flux tilts <1%.
The inspector noted reactor engineering's quality operations support and thorough engineering evaluation. The inspector noted that the reactor engineer evaluation was well detailed and timely. The inspector concluded that, in this instance, reactor enginer ing technical expertise, and conservative support of operations contributed to safe plant performance.
4.2 Scaffolding in Safety-Related Areas During the inspection period, the inspector noted several examples of the licensee's failure to adequately control scaffolding in safety-related areas i
in accordance with NC.NA-AP.ZZ-0023, Scaffolding and Transient Loads Control.
The inspector observed minor deficiencies regarding adequate clearances, proper restraints, variance inspections, and timely removal. Safety-related areas included the service water bays and 4ky vital electrical bus room. The 1
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8 inspector noted the operating shifts' timely response in addressing the deficiencies. The inspector did not observe any discrepancies that directly i
impacted or threatened nuclear safety presently.
4.3 Safeguard Equipment Control (SEC) Troubleshooting f
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The inspectors documented in previous inspection reports (see NRC Inspection 1
Reports 50-272/94-31 and 94-35) recurring problems with Unit 1 SEC degraded j
power supplies and frequent automatic test insertion (ATI) test faults and spurious alarms. The inspector noted 12 instances of ATI test faults on IA SEC and 1 on IB SEC. On February 22, 1995, maintenance replaced the 1A SEC 24 volt power supply to restore the 1A SEC to operability. This same power supply was replaced on January 6, 1995.
System engineering, together with nuclear engineering, have remained focused in their pursuit of SEC problem resolution. While engineering could not-deterrine a definitive root cause, it was hypothesized that the spurious alarms and test faults were caused in part, by electromagnetic interference (EMI) or electrical noise. Accordingly, the licensee contracted an EMI specialist in mid-February to investigate the frequent ATI test faults.
Engineering, supported by the EMI specialist, determined that EMI levels in the SEC cabinet, although high enough to cause ATI alarms, do not impact the ability of the SEC to perform its designed safety function.
Engineering is actively pursuing the EMI specialist's recommendations to improve the immunity of the ATI to EMI and to prevent future spurious ATI alarms.
System engineering plans to implement on-line monitoring to evaluate the potential for electrical bus disturbances affecting the ATI test circuit.
In addition, engineering is in the final stages of preparing a design change package (DCP) to replace the SEC power supplies, implement needed EMI improvements, and install an ATI resistor modification. Engineering concluded, based upon Unit 2 SEC fault-free operating experience,-that the new power supplies, good EMI practices, and the ATI card modification resolved the problem of erroneous ATI alarms previously experienced on Unit 2.,
Engineering is also working closely with the SEC vendor to improve EMI immunity.
The inspector noted that engineering determined that although power supply AC ripple voltage was found to be higher (4mv) than the vendor's acceptance criteria (Imy), it.was still far below the point that the vendor stated that it could impact SEC operability (2.4 volts) for a 24 volt power supply. The i
inspector determined that while SEC test faults persist at a frequent periodicity, engineering is actively engaged in monitoring and diagnosing system performance.
4.4 Pressurizer Code Safety Valve Loop Seals 4
On October 19, 1994, during Salem Unit 2 refueling outage 2R8, maintenance technicians prepared to remove pressurizer safety valve (PSV) ?P43 for routine testing. When the? separated the faces of the inlet flange they encountered water leaking from the pipe connecting the pressurizer to the valve.
In response to the leaking water, an equipment operator found valve 2PR66 closed.
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As a result, water had collected th the inlet piping, configured by original
. plant; design, to permit formation of a loop seal containing approximately ten gallons of water.
During the previous refueling outage, PSE&G installed a modification, Design Change Package (DCP)-2EC-3190, in response to NUREG 0737, Item II.D.1, to address the concern that operation of the PSVs (2PR3, 2PR4, and 2PR5) with a loop seal would result in stress levels in excess of Code allowable on the structural welds and discharge piping. The modification replaced the PSV l
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internals with internals designed to operate in a steam only environment. _In l
addition, the modification installed drain lines for the loop seals. The drain lines from each of the PSVs had individual isolation valves, and a I
common isolation valve (2PR66) in the common drain line header.
The licensee concluded that Salem Unit 2 had operated from the end of refueling outage 2R7 (May 1993) until the beginning of refueling outage 2R8 with the loop seals not drained.
Engineering reviewed existing analyses and initially concluded that, although an analysis did not exist to cover operation of the PSVs under the exact conditions that existed between 2R7 and 2R8, analyses with sufficient similarity existed to provide reasonable assurance that the PSVs and their associated discharge piping would have performed their safety function if they had been challenged. They concluded that demonstrating the valves had been operable required a detailed analysis.
Notwithstanding, more recent evaluation indicates that operation of the PSVs under design conditions would have resulted in loads on the discharge piping in excess of Code allowable. Nuclear engineering initiated the detailed analysis, scheduled for completion in April 1995, to determine the safety significance of this matter and whether operability would have been affected.
Salem management tasked the operations staff with determining the root cause for mispositioning the valve. Operations scheduled the task for completion on March 26, 1995. The inspectors, with the assistance of operations si.aff, determined that the modification package (2EC-3190) contained a requirement to add the valves installed as part of the modification, including 2PR66, to the database used to control valve lineups. The modification required that operations place 2PR66 in the open position for normal operation. The inspector noted that 2PR66 was added to the database on May 4, 1993, and was assigned to lineup RC MECH 001 on May 18, 1993.
The inspector noted that the operations staff performed lineup RC MECH 001 on May 10, 1993. The operations indicated that they typically controlled the lineup of components affected by modifications during a refueling outage through the use of auxiliary lineups. However, the operations staff could find no evidence that operators had performed an auxiliary lineup for 2PR66 but did find several examples of completed auxiliary lineups associated with other 2R7 modifications.
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The operations staff reviewed the work order that implemented modification 2EC-3190, and could find no evidence of a post-modification test to verify that the loop drain performed its intended function. The operations staff e
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s 10 also demonstrated that the database currently contained 2PR66 assigned to lineup RC MECH 001, and that operators had correctly positioned the valve at the conclusion of the 2R8 refueling outage.
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The inspectors noted that the difficulty experienced with the PSVs leaking past the seat at the. end of 2R8 further demonstrated that operators correctly
- positioned 2PR66 after 2R8, and the lack of seat leakage after 2R7 tended to i
i-l support the conclusion that 2PR66 was erroneously left in a closed position i
for the entire cycle following the 2R7 outage, and not detected until after t
the completion of the 2R8 outage.
The inspectors concluded that PSE&G had operated Salem Unit 2 from at power l
between the end of refueling outage 2R7 in May 1993, and the beginning of r
refueling outage 2R8 in October 1994, with an unanalyzed configuration associated with the pressurizer safety valves. The licensee is currently j
performing a detailed evaluation.to determine if the valves were operable in that period in view of the different type of valve internals and other j
configuration changes that were installed to support removal of the loop seals.
Failure to ensure that modification 2EC-3190 was satisfactorily completed is an apparent violation of 10 CFR 50, Appendix B, Criterion V.
(EEI 50-272;311/95-02-02).
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Associated with this apparent violation is the continuing weakness in the licensee's process and program for root cause and corrective action effectiveness as demonstrated by the fact that, while the licensee ensured that operators opened 2PR66 prior to startup after 2R8, there was no assessment made to determine the causes of the circumstances that led to the as found condition, no consideration of the potential for other component or configuration problems, or no determination of the adequacy of implementation and performance of post-modification / installation testing for other modifications completed during 2R8.
4.5 Control of Reactor Head Vent Material, Parts, and Components During a review of information in the Managed Maintenance Information System-(MMIS) data base, the inspector noted that MIS listed the open and closed limit switches for position indication of the reactor vessel head vent valves as not safety-related, not environmentally qualified, not seismically qualified, and not requiring quality control. The inspector noted that 10 CFR 50.44 C (3) (iii) and the guidelines of NUREG 0737 Item II.B.1 require operability of the reactor head vent valves and that the reactor head vent limit switches provide continuous positive valve indication during plant i
operation.
In addition, the limit switches are required to be seismically and environmentally qualified in accordance with IEEE 344-1975.
The inspector found that on June 7, 1994, Procurement Engineering had i
initiated Discrepancy Evaluation Form (DEF) DES-94-00071. The importance of i
the need for qualified components was recognized in the DEF by indicating that two reactor head vent valves were on the same circuit; and consequently, a shorted limit switch would open the circuit breaker supplying both valves l
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r 11 rendering them both inoperable. Nothwithstanding, though the DEF acknowledged that the switches appeared to be improperly classified, there was no concern indicated relative to operability or safety significance.
In response to the DEF, on June 16, 1994, the licensee initiated a Bill Of Materials (BOM) change to reflect the requirement that the limit switches be obtained seismically and environmentally qualified.
It was not until February 1995 that the plant staff determined that non-qualified limit switches had been installed in Salem Unit I reactor head vent valves IRC41 and IRC43. All other head vent valve limit switches were found to be appropriately qualified.
The licensee also issued a work order for I&C-action to replace the limit switches during the next Salem Unit I refueling outage, presently scheduled for September 1995.
The licensee determined that the manufacturer's part number for the non-qualified limit switch was-the same as the part number for the qualified limit switch, and determined that the limit switches installed in IRC41 and IRC43 were manufactured to the same standards as limit switches obtained as safety related parts; the exception being that qualified parts are certified by testing. Consequently, the licensee concluded that installation of the non-qualified limit switches constituted a loss of quality (as discussed in NRC Generic Letter 91-18), but not a loss of operability.
The inspector reviewed an Ni!S Bill of Material Validation report, documenting engineering assessment of Purchase Class 4 codes (commercial grade,' non-safety related) assigned to safety related components.
Engineering initiated the assessment as a result of identification that, in August 1994, a rheostat
- designated for use in safety-related Salem battery chargers had been obtained as a commercial grade component. The report documented that, in a review of approximately 500 Purchase Class 4 components, 76% were appropriately classified. The remaining 24% required further engineering evaluation to permit use in' safety-related applications, or were inappropriately classified.
The report further recommended that an additional _497 items should be reviewed '
in depth to determine if they are acceptable for use in safety-related applications.
Engineering expected to begin the review in March and complete the review by June 30, 1995.
The inspector determined that relative to the DEF, the engineering staff did not have sufficient bases to conclude that no operability or safety concern existed, particularly since the DEF recognized that a short of a single limit switch could affect operability of two reactor head vent valves. Further, the engineering staff apparently did not determine that non-qualified switches had been actually installed in IRC41 and IRC43 until February 1995. Consequently, the inspector determined that the licensee did not take adequate or timely corrective action in response to the deficiency identified in the DEF.
The inspector noted that a similar problem was identified the April 7,1994, Unit I loss of circulating water.
In that case, the NRC issued a Notice of Violation that addressed the installation of incorrect parts in PORVs 2PRI and 2PR2, and installation of a summator module for high steam flow setpoint with incorrect identification and an incorrect electronic part. The corrective
12 action for those findings apparently was insufficient to assure critical l
evaluation and review of the potential for other instances of the installation of incorrect parts in safety related applications.
Failure to take adequate corrective actions relative to the identification of non-qualified limit switches on the safety-related reactor head vent valves is l
an apparent violation of the requirements of 10 CFR 50, Appendix B, Criterion i
XVI, Corrective Action (EEI 50-272;311/95-02-03).
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4.6 Reactor Head Vent Valves i
The reactor head vent valves were installed as one of the action items of i
NUREG-0737, " Clarification of TMI Action Plan Requirements." For each Salem unit, four solenoid-operated valves provide redundant flow paths for post-accident venting of hydrogen from the reactor vessel head. The valves are not i
used during power operation, however, they are part of the roactor coolant system (RCS) pressure boundary.
On Jul'y 6, 1994, Unit 2 was in cold shutdown when operators attempted to i
stroke reactor head vent valve 2RC40. When the valve's open position indication light did not illuminate, operators initiated a work request.
During maintenance to repair the suspected indication problem, the licensee discovered that the valve had actually failed to stroke open (through use of vendor supplied diagnostic equipment).
In a memorandum dated July 7, 1994, maintenance engineering informed operations that the "most probable" cause of the failure was boric acid that may have solidified around or in the valve's pilot plug. According to the memorandum, when RCS temperature was increased above 180"F, the valve could be opened. Subsequent testing demonstrated that the valve stroked within specifications and would pass the appropriate flow for the given plant conditions. The memorandum recommended the valve be returned for normal use, and that the need for additional preventive maintenance should be evaluated.
There were, however, no recommendations for addressing the generic implications or impact of this finding on nuclear safety. No discrepancy report was initiated for evaluation of this safety-related component failure.
The inspector reviewed incident reports from that period, and was not able to find documentation of 2RC40's failure to stroke open. Similarly, a licensee review of completed maintenance work packages from the 1994 summer outage found no documentation that specifically addressed the failure of 2RC40 to stroke. Salem Administrative Procedure NC.NA-AP.ZZ-0009(Q), " Work Control Process," requires workers to report incorrect operation of safety-related components to their supervisors. Supervisors are required to evaluate such problems against criteria for in41ation of an incident report contained in of NC.NA-AP.ZZ-00064Q), " Incident Report / Reportable Event Program and Quality / Safety Concerns Reprting System."
The inspector determined that the failure of 2RC40 met the procedure's criteria (Attachment 1, " Examples of Off-normal Events," Item 8b) and the subsequent failure to enter the finding as an incident report circumvented an established quality deficiency reporting and corrective action system. As a
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i result, the systems engineering organization was not involved, and the safety
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-impact, generic implications, and root cause were not adequately evaluated.
In addition, there was no review by engineering management.
l Since July 1994, all four reactor head vent valves in Unit 2 have been l
replaced (due to leakage problems) and, therefore, the immediate safety significance of this issue is low. However, there has been no determination if this failure constitutes a potential common mode failure.that may effect all reactor head vent valves over time.
In addition, no assessment has been made to determine the impact on plant safety should one or more of these valves fail, undetected.
The failure to identify the deficiency and effect corrective actions are apparent violations of Salem Administrative Procedure, NC.NA-AP.22-0006(q) and 10 CFR 50 Appendix B Criterion XVI, " Corrective Action" (EEI 50-272;311/95 04).
4.7 Review of Enforcement Discretion Requests The inspector reviewed ten licensee requests for enforcement discretion, covering the period from October 1987 through January 1994. Typically, the licensee initiated the requests to allow maintenance' or troubleshooting activities to continue without changing modes, e.g., replacement of an individual battery cell for the IC 125VDC battery, testing of No.13 auxiliary feedwater pump, replacement of the motor for No. 22 containment fan coil unit motor, replacement of degraded piping in the core spray system, degassing of No. 1-station power transformer insulation oil, and conducting a special test 1
of main steam isolation valves. One request asked for relief from continuing a shutdown because the licensee anticipated imminent issuance of a waiver of compliance that would obviate.the need to shutdown. For each request, the l
inspector determined that until the NRC granted enforcement discretion the licensee complied with the applicable Technical Specification conditions for operation and associated action statements, and verified that the licensee complied with the reporting requirements of 10CFR50.72 and 10CFR50.73. The inspector concluded that the licensee had properly operated the units and met reporting requirements.
The inspector also reviewed a justification for continued operation (JCO) the licensee submitted June 17, 1993 in response to control rod malfunctions. On May 27, 1993, with a startup of Unit 2 reactor in progress, a control rod cluster withdrew when given an insert demand signal. On June 4, the licensee completed their investigation into the anomaly and concluded there was a potential unreviewed safety question with respect to rod control.
In response, Unit 2 operators inserted all control rods. They also submitted a JC0 for Unit 1, which was operating at 100% power. The inspector determined that, as in the instances of enforcement discretion requests, the licensee operated the plants in accordance with TS while the investigation was in progress and while awaiting NRC review and approval of the JCO. The inspector concluded that the licensee operated the units safely and the licensee l
complied with the reporting requirements of 10CFR50.72 and 10CFR50.73.
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14 l
4.8 Reactor Head Leakage Detection System on March 17, 1988, the NRC issued Generic Letter (GL) 88-05, " Boric Acid Corrosion Of Carbon Steel Reactor Pressure Boundary Components in PWR Plants,"
in response to several incidents where leaking reactor coolant caused significant corrosion problems. The GL discussed the effects of concentrated boric acid. solution or boric acid crystals, formed by evaporation of leaking coolant, on reactor coolant pressure boundary components.
In many instances, licensees had detected the existence of leaks, but had not evaluated their
- potential impact on plant safety or taken timely corrective action.
In a response letter, dated May 27, 1988, PSE&G described enhanced monitoring techniques and procedures, and specific inspection criteria to address this concern. The letter also described a design change intended to improve the detection of small reactor coolant leaks. A reactor head leakage detection system, currently referred to as the main coolant system leakage air particulate monitor (MCSLAPM), was installed as an " experimental system" to provide continuous control room indication of radiological conditions above the reactor head, inside the control rod drive mechanism (CRDM) ventilation shroud. Although not explicitly described in the licensee's May 1988 letter, the MCSLAPM was principally intended for evaluating the effectiveness of temporary clamps installed on thermocouple and spare control rod drive columns.
The inspector revieweo the licensee's GL response and discussed the MCSLAPM system with Radiation Controls and Engineering personnel.
Based on interviews with those responsible for the system, MCSLAPM has had no routine calibration or surveillance since installation in mid-1988. Corrective maintenance had been performed on at least one occasion after the system had obviously failed.
However,' licensee personnel believe that this system has provided qualitative trend information, based on past instances when the MCSLAPM indicated increased activity, coincident with indications from the safety related containment air monitoring system. Currently, a radiation monitoring system upgrade program is being implemented at Salem, which proposes removal of the MCSLAPM system and installation of a sample pump for the CRDM ventilation plenum. The proposed sample pump would be'different from the MCSLAPM because it would require a containment entry for operation and would not provide on-line information.
The inspector noted that the experimental system mentioned in the licensee's GL response letter is currently in use at Salem. Despite the fact that the MCSLAPM has not been maintained or tested as a calibrated system, trend information from the MCSLAPM could help operators differentiate between leakage from the reactor head and leakage elsewhere in containment. The system is not classified as safety-related, and the inspector was unable to find additional information regarding the MCSLAPM on the Salem docket or in the Final Safety Analysis Report. The inspector noted that the temporary clamps installed in 1988 have since been replaced by seal welds. Also, tk central issue of GL 88-05 (i.e., detection of boric acid corrosion) has Leen satisfactorily addressed through procedural enhancements, plant walkdowns by system engineering personnel, and additional checks for boric acid e
7----
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i 4
15 accumulation during post-outage and at-power containment inspections. The inspector noted that PSE&G's commitment (in the "LR-N980190, Informs of One Time Rev to Commitment to Specific Provisions Contained in NRC SER to Perform Weld Root Pass Surface Nde. Instead of Volumetric Exam on Pressure Boundary,Asme Class 3 Component Was Performed,Per Requirements of [[CFR" contains a listed "[" character as part of the property label and has therefore been classified as invalid..59|May 27, 1998, letter]]) was only for initial use of the experimental monitoring system.
5.0 PLANT SUPPORT 5.1 Radiological Controls 5.1.1 Failure to Sample Waste Gas Decay Tank (WGOT) on Unit 2 Licensee Event Report 94-15 identified that operators failed to collect grab samples of the WGDT as required by Technical Specifications (TS). On September 27, 1994, and October 1,1994, No. 22 WGDT was placed in service, but without the sample line in service. The line was isolated due to the i
sample isolation valve being tagged shut. However, operators failed to note valve position during their review of the off-normal and tagged list.
J Consequently, the gaseous effluent monitoring instrumentation channels required by TS 3.3.3.9 were effectively inoperable. Without the required operable channels, TS allows continued WGDT operation provided grab samples i
are collected at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Operators did not collect the grab samples.
On the two occasions when No. 22 WGDT was in service without the sample flow path the concentration of oxygen in the system prior to the event was.726%
and following the event was below.17%.
Since the TS limit for oxygen concentration is 2%, the inspector concluded the failure to collect grab samples had minimum safety consequence.
The licensee's corrective actions *.ncluded issuing an Information Directive that reiterated management's expcctations associated with review of components' off-normal reports, and counseling the involved personnel.
The inspector concluded that failure to perform grab samples by TS met the criteria established in 10 CFR 2, Appendix C, Section VII.B for a non-cited issue.
It was not a violation that could not have been expected to be prevented by the corrective actions for a previous violation since there have been no similar events involving missed oxygen grab samples. Once the line-up error was discovered, the licensee took immediate corrective action to establish the sample flowpath and sampled the WGDT for oxygen, and initiated long-term corrective actions that re-emphasized management's expectations regarding review of off-normal reports. Finally, the inspector did not find any evidence that suggested operators had willfully isolated the sample flow path or failed to perform grab samples.
5.2 Emergency Preparedness The inspector reviewed PSE&G's conformance with 10 CFR 50.47 regarding implementation of the emergency plan and procedures.
In addition, the inspector reviewed licensee event notifications and reporting requirements per 10 CFR 50.72 and 73.
m
16 5.2.1 Unusual Event Due to Low Water Level At 7:41 p.m. on February 5,1995, the licensee entered SI.0P-AB.ZZ-0001, Severe Weather, due to high winds and heavy precipitation. At 9:30 p.m., the licensee declared an Unusual Event for Salem Units 1 and 2 due to a low water level in the Delaware River. River level dropped to 83 feet. The Salem Senior Nuclear Shift Supervisor (SNSS) declared an Unusual Event based upon Event Classification Guide (ECG) Section 12.G - Water Level s 83.0 feet.
Both Salem units were in Mode 5 (Cold Shutdown) at the time and were unaffected by the low water level condition. The licensee's primary concern was the continued operability of the service water system due to service water pump net positive suction head (NPSH) requirements. The licensee calculated the pump NPSH to be 43.3 feet at low water level (83 feet).
Licensee procedures require a service water flow reduction if NPSH drops below 39.5 feet. The licensee concluded that high winds due to storm conditions, in conjunction with low tide, caused the low river water level condition.
At 11:30 p.m., the licensee terminated the unusual event, based on river water level at 83.75 feet and increasing.
In addition, the licensee exited SI.0P-AB.ZZ-0001, Severe Weather, at 12:22 a.m. on February 6.
j The inspector independently verified the licensee's actions and calculations in accordance with station ECG and procedural guidelines. The inspector noted that the low water level condition had no effect on the Salem units and the procedural guidance was adequate to ensure plant safety. The inspector i
determined that the licensee's actions and ECG notifications were prompt and appropriate.
6.0 REVIEW OF REPORTS AND OPEN ITEMS The inspectors reviewed the Salem Monthly Operating Reports for January for accuracy and content, and found them acceptable. The inspectors also reviewed the following Licensee Event Reports (LERs) to learn whether the licensee took the corrective actions stated in the report, and to detect if the licensee responded to the events adequately, met regulatory requirements conditions, and commitments:
Salem Unit 1 Number Event Date Description LER 94-018 December 9, 1994 Design basis ccncern due to inoperability of IA Safeguards Equipment Controller and subsequent TS 3.0.3 entry due to inoperability of 1A and IB SECS The inspectors determined that the LERs listed above did not identify any violations beyond those previously identified in NRC Inspection Reports, and l
considered the LERs closed.
ATTACHMENT 4 May 24, 1995 Mr. Leon R. Eliason President and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
SALEM RESIDENT INSPECTION NOS. 50-272/95-07; 50-311/95-07
Dear Mr. Eliason:
The enclosed report documents an inspection for public health and safety, conducted by Mr. C. Marschall, Senior Resident Inspector and other members of the NRC resident and regional staff at the Salem Nuclear Generating Station J
for the period between March 23, 1995 and May 6, 1995. The inspectors discussed the findings of this inspection with Messrs. J. Summers, General Manager-Salem operations, and other members of your staff.
During this period, we detected that performance standards and expectations for the Salem Station Operating Review Conmittee (SORC) were not well developed or communicated. Consequently, the SORC did not demonstrate a systematic approach or questioning attitude relative to the review and evaluation of matters, such as safety assessments required by 10 CFR 50.59 and operability determinations involving the safety impact of certain degraded plant conditions. This weakness compounds our previous concerns involving the continuing challenge to operators from degraded conditions that constitute "workarounds", the quality of operability determinations, root cause determination and corrective action effectiveness, plant equipment reliability, and work planning and control effectiveness.
Within the scope of this inspection, the inspectors and your quality assurance organization identified several examples of inadequate problem identification and resolution of deficiencies associated with safety related equipment.
In each of these instances your system engineering staff was aware of information that constituted a degraded condition, but failed to take timely and appropriate action to resolve the matters. Consequently, the matters described in Enclosure 2 are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy), 10 CFR Part 2, Appendix C.
Accordingly, a Notice of Violation is not being issued for these inspection findings at this time. The r, umber and characterization of the apparent violations may change as a result of further NRC review. Accordingly, no response to these matters is required at this time.
These apparent violations (as described in the enclosure) were discussed between Mr. John Summers, General Manager-Salem Operations, Mr. Jeffery Benjamin, General Manager-Quality Assurance and Nuclear Safety Review, and Mr.
John White of our office on May 17, 1995. Accordingly, these matters will be discussed in a previously scheduled Enforcement Conference on June 1,1995.
This conference will be closed to public observation.
gfo(401WW
i Mr. Leon R. Eliason 2
The decision to hold an Enforcement Conference does not mean' violations have i
occurred, or that enforcement action will be taken. The purposes of this conference are:
(1) To discuss the apparent violations, including cause and safety significance; (2) to provide you with an opportunity to point out errors in our inspection report, and identify corrective actions, taken or planned; and (3) to discuss any other information that will help us detemine the appropriate action in accordance with the Enforcement Policy. The conference is also an opportunity for you to provide any information concerning your perspectives on the severity of the apparent violations, and the application of the factors that the NRC considers when it determines the i
amount of a civil penalty that may be assessed in accordance with Section VI.B.2 of the Enforcement Policy.
Based on the results of this inspection, it also appears that certain of y0ur activities were not conducted in full compliance with NRC requirements, as set forth in the enclosed Notice of Violation and Notice of Deviation. These matters indicate continuing weaknesses relative to control of maintenance activities, procedure adherence, and 10 CFR 50.59 applicability reviews and safety evaluations.
You are required to respond to this letter and should follow the instructions specified in the enclosed Notices when preparing your response.
In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. Your response may reference or include previous docketed correspondence, if the correspondence adequately l
addresses the required response. After reviewing your response to the Notices, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
Based on the results of this inspection, it appears that you failed to adhere to the requirements of Technical Specification 6.11 concerning procedures for personnel radiation protection on March 24, 1995. Since your radiation protection organization identified this violation, and our inspectors confirmed that you met the criteria for enforcement discretion as specified in 10 CFR 2, Appendix C, Section VII, this violation will not be cited.
In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosures will be placed in the NRC Public Document Room.
The responses directed by this letter and enclosed Notice are not subject to the clearance procedures of the office of Management and Budge as required by the Paperwork Reduction Act of 1980, Public Law No. 96.511.
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l Mr. Leon R. Eliason 3
Your cooperation with us is appreciated.
Sincerely, ORIGINAL SIGNED BY:
Richard W. Cooper, Director Division of Reactor Projects Docket Nos. 50-272; 50-311
Enclosures:
1.
Appendix A, Notice of Violation 2.
Appendix B, Notice of Deviation 3.
Apparent Violations Considered for Escalated Enforcement 4.
NRC Inspection Report Nos. 50-272/95-07; 50-311/95-07 cc w/ encl:
J. J. Hagan, Vice President-Operations S. LaBruna, Vice President - Engineering and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
R. Burricelli, General Manager - Information Systems & External Affairs J. Summers, General Manager - Sales Operations J. Benjamin, Director - Quality Assurance & Safety Review-F. Thomson, Manager, Licensing and Regulation R. Kankus, Joint Owner Affairs A. Tapert, Program Administrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. J. Curham, Manager, Joint Generation Department, Atlantic Electric Company Consumer Advocate, Office of Consumer Advocate William Conklin, Public Safety Consultant, Lower A110 ways Creek. Township
- Public Service Commission of Maryland State of New Jersey State of Delaware 1
Mr. Leon R. Eliason 4
Distribution w/ enc 1:
Region I Docket Room (with concurrences)
Kay Gallagher, DRP l
Nuclear Safety Information Center (NSIC) l D. Screnci, PA0 (2) l NRC Resident Inspector PUBLIC Distribution w/ encl: (Via E-Mail)
L. Olshan, NRR W. Dean, OEDO J. Stolz, PDI-2, NRR M. Callahan, OCA Inspection Program Branch, NRR (IPAS)
DOCUMENT NAME: a:9507. sal To
- w. a copy se se encument, haam h en nec v - copy wwat annehment/endoeur. T - cwy wnn attachment /endoeur. T = No copy 0FFICE RI:DRP RI:DRP RI:DRP l
l NAME CMarschall JWhite RCooper DATE 5/ /95 5/ /95 5/ /95 0FFICIAL RECORD COPY
l APPENDIX A NOTICE OF VIOLATION Public Service Electric and Gas Company Docket Nos: 50-272; 50-311 Salem Nuclear Generating Station Units 1 and 2 License Nos: DPR-70; DPR-75 During an NRC inspection conducted on March 23, 1995 - May 6, 1995, violations of NRC requirements were identified.
In accordance with the
" General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C, the violations are listed below:
A.
Technical Specification 3.7.6 for Salem Unit 2 requires that control room emergency air conditioning shall be operable in all modes with at least two operable isolation dampers in each outside air intake duct.
The Technical Specification 1.18 definition of operability requires that, in order for a component to be considered capable of performing its intended function, all auxiliary equipment that is required for the component to perform its function is also capable of performing its related support function. The design of the control room emergency air conditioning dampers requires that either radiation monitor 2RIA or 2RIS be capable of initiating isolation of the dampers on high radiation in the control room emergency air conditioning ventilation intake duct.
With no operable dampers, the licensee shall meet the requirements of Technical Specification 3.0.3, which requires that the licensee shall within I hour take actions to place the unit in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, at least hot shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and at least cold shutdown within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
i Contrary to the above, from 9:20 a.m. on April 4, 1995, to 3:24 a.m. on April 5,1995, with Salem Unit 2 in mode 1, the licensee blocked actuation of both 2RIA and 2 RIB on high radiation in the control room air conditioning ventilation intake duct rendering the isolation dampers incapable of isolating on high radiation, and failed to take the actions required by Technical Specification 3.0.3.
This is a Severity Level IV violation (Supplement I).
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Technical Specification 6.8.1 requires, in part, that written procedures B.
be established, implemented and maintained covering the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, i
Revision 2, February 1978. Regulatory Guide 1.33 requires that maintenance that can affect the performance of safety related equipment be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the i
j circumstances. Licensee Procedure NC.NA-AP.ZZ-0009, step 5.1.1.a requires procedures to control safety related activities and maintenance on security equipment, and step 5.7.1 requires that individuals perfom work in accordance with the established work package; and procedure i
NC.NA-AP.ZZ-0023, Scaffo7 ding and Transient loads Contro7, provides instructions for controlling the erection and storage of scaffolding in safety related areas and requires that scaffolding in safety related ereas have adequate clearances, cross-braces, restraints, and variance j
apprcyal, and be removed in a timely manner following completion of mainteriance.
3 Contrary to the above:
On April 26, 1995, plant staff performed hot spot flushing which affected the safety-related Refueling Water Storage Tank (RWST) and safety injection system without a procedure to control the activity; On May 4,1995, plant staff performed work on the safety-related no. 23 service water pump without a procedure or a work package; On April 18, a security guard corrected a malfunctioning security door without a procedure or a work package; scaffolding installed in the vicinity of the no.11 On April 26, auxiliary feedwater pump (AFP) and the room cooler for the Sales unit I motord riven AFPs did not have the required clearance, cross-bracing, restraints, or variance approval; and, On May 1, scaffolding around the Salem Unit 2 containment fan cooler unit service water piping was not removed in a timely manner following completion of the work on January 25, 1995.
This is a Severity Level IV violation (Supplement 1).
10 CFR 50.59 requires that changes to the plant, as described in the C.
Updated Final Safety Analysis Report (UFSAR), be evaluated to determine that they do not constitute an Unreviewed Safety Question (USQ), and that records of changes must include a written safety evaluation which provides the bases for the determination that the change does not involve an USQ.
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i Contrary to the above:
A 10 CFR 50.59 applicability review, dated April 7,1995, failed to provide an adequate basis for the determination that a degraded IA-125VDC battery cell (no. 35) post seal did not constitute an Unresolved J
Safety Question; A Safety Evaluation, dated April 3,1995, failed to provide the basis
~
for the determination that use of a Service Water Intake area exhaust fan motor, used to replace a fan motor in the no. 22 RHR room cooler unit did not constitute an Unreviewed Safety Question.
1 i
This is a Severity Level IV violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, Public Service Electric and Gas company is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Cosatssion, ATTN: Document Control Desk, Washington, 4
D.C. 20555 with a copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each violation:
(1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the results achieved, (3)d (4) the the corrective steps that will be taken to avoid further violations, an date when full compliance will be achieved. Your response may reference or include previous docketed correspondence, if the correspondence adequately addresses the required response.
If an adequate reply is not received within the time specified in this Notice, an order or a Demand for Information may be issued as to why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time.
Dated at King of Prussia, Pennsylvania this 24th day of May 1995
APPENDlX 5 l
NOTICE OF DEVIATION g
Public Service Electric and Gas Company Docket Nos: 50-272 Sales Nuclear Generating Station Units 1 and 2 License Nos: DPR-70 i
i During an NRC inspection conducted on March 23, 1995 - May 6, 1995, a deviation of NRC requirements was identified.
In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C, the deviation is listed below:
The basis for Sales Unit 1 Technical Specification 3.8.1 states that the surveillance requirements for demonstrating operability of the Emergency Diesel Generators (EDG) are based on the recommendations of Regulatory Guide (RG) 1.9, and RG 1.108. RG 1.108 (Rev. 1, August 1977), a licensee commitment, requires nonconcurrent testing of redundant Emergency Diesel Generators during normal plant operation.
Contrary to the above, at least two EDG output breakers were simultaneously closed from 4:19 a.m. until 5:22 a.m. on May 5, 1995, to support concurrent testing of the 1A and IC Emergency Diesel Generators.
r Please provide to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555, with a copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at Salem Generating Station, in writing within 30 days of the date of this Notice, (1) the reason for the deviation, or if contested, the basis for disputing the deviation, (2) the corrective steps that have been tden and the results achieved, (3) the corrective steps that will be taken to avoid further deviations, and (4) the date when your corrective action will be completed.
Where good cause is shown, consideration will be given to extending the response time.
Dated at King of Prussia, Pennsylvania this 24th day of May 1995 i
D) L & & (r 0 k O ~l N " f
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APPARENT VIOLATIONS CONSIDERED FOR ESCALATED ENFORCEMENT
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10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part, that licensees shall promptly identify and correct conditions adverse to quality, and for significant conditions adverse to quality, the licensee shall also document the condition, notify appropriate levels of management, and i
ensure action to preclude recurrence of the condition.
Contrary to the above, the Sales engineering staff did not promptly identify, l
correct, notify appropriate levels of management, or ensure action to preclude recurrence for the following conditions:
(1)
An oil sample laboratory report, dated August 4,1994, recommended resampling and changing the oil on the no. 21 high-head safety injection pump based upon a ten-fold increase in wear particle concentration.
(2)
An oil analysis, dated November 28, 1994, identified high wear particle concentration in the no. 22 high-head safety injection pump speed increaser oil.
On March 20, 1995, the responsible system engineer issued Equipment Malfunction Identification System (EMIS) tags on the above components identifying the degraded conditions.
l (3)
A lab report, dated October 6,1994, recommended resampling the no. 23 f
Auxiliary Feed Water (AFW) turbine lube oil due to a trace amount of water found and a marked increase in wear particle concentration.
On March 27, 1995, the system engineer issued an EMIS tag addressing this. degraded condition. The inspector noted that the engineer had little or no documentation on the above problems other than the initial l
lab reports.
(4)
In May 1994, a system engineer initiated a work request to inspect the 2Al 28 VDC battery charger ground detection circuit (GDC) wiring. He initiated the request following a system walk-down of the 28 Y battery chargers that revealed Unit I chargers were configured differently than Unit 2 chargers. However, the work order to conduct the charger internal inspection did not occur until late April 1995.
(5)
Licensee Event Report (LER) 95-05 identified seven instances of vendor identified out of tolerance pressurizer code safety valves (PSVs). The report stated that, between May 8, 1990 and January 14, 1995, the vendor identified that the PSVs did not meet the 1% tolerance required by Technical Specification 4.0.5 requirement for Salem Unit 1.
The LER further stated that the four instances between November 14, 1994 and January 14, 1995 each identified that two of the installed three PSVs did not met the Technical Specification (TS) 4.0.5 tolerance In each case, the vendor notified the appropriate system requirement.
i engineer by telephone, and followed the telephone report with a written j
j report.
In all cases, Sales personnel informed by the vendor failed to I
initiate an Incident Report. As a result, PSE&G did not initiate timely root'cause or reportability evaluations.
i l
i U. S. NUCLEAR REGULATORY COMMISSION REGION I l
Report Nos.
50-272/95-07 50-311/95-07 License Nos.
DPR-70 DPR-75 Licensee:
Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facility:
Salen Nuclear Generating Station Dates:
March 23, 1995 - May 6, 1995 Inspectors:
C. S. Marschall, Senior Resident Inspector J. G. Schoppy, Resident Inspector i
T. H. Fish, Resident Inspector L. M. Harrison, Reactor Engineer ORIGINAL SIGNED BY:
5/23/95 Ap.9 roved:
John R. White, Chief Date Reactor Projects Section 2A Insoection Spigmary:
This inspection report documents inspections to assure public health and safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security, engineering, technical support, safety assessment and quality verification.
The Executive Summary delineates the inspection findings and conclusions.
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i EXECUTIVE SulOIARY Salem Inspection Reports 50-272/95-07; 50-311/95-07 i
i March 23, 1995 - May 6, 1995 OPERATIONS (Module 71707,92901) The inspector noted that equipment deficiencies continued to provide daily challenges to control room operators.
l Previous NRC inspection reports identified degraded conditions, work-arounds and distractions to operators. The inspector noted that Unit I control room operators endured 13 surveillance tests, 8 technical specification entries, 5 abnormal overhead annunciators, and 14 emergent equipment deficiencies during
}
one 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.in early April. Although this may not represent a typical day, Sales operators frequently experience challengas that provide increased 5
i risk of personnel error and increased challenge to safe plant operation due to l
equipment unavailability.
Inspectors noted continued operator focus on identifying and correcting equipment deficiencies in a time frame suitable to 4
l its importance to safety.
In response to discussions with the inspectors, operators increasingly questioned how degraded conditions affected the ability of a system, sua-system, or component to perfom its intended function as captured in the design basis. Notwithstanding, the licensee continues to demonstrate less than adequate performance relative to operability determinations and safety evaluations, particularly with respect to l
recognition and appreciation of the established design basis for the effected component or system.
MAINTENANCE / SURVEILLANCE (Nodules 61726,62703) During the inspection
{
period, the inspectors noted several examples of less than adequate j
maintenance planning. The improper planning resulted in safety related equipment not available when required and workers performing a significant i
l number of activities under apparent pressure resulting from time limitations, i
Such inadequate planning efforts could put the plant at increased risk due to l
personnel error and safety-related equipment reliability.
i i
The inspectors identified two examples of failure to properly control safety-related equipment. One incident involved the failure to follow prescribed l
work control procedures, the other involved an activity that was conducted l
without an approved procedure.
I 1
i The inspectors identified two additional instances of failure to properly i
control scaffolding in safety-related areas. Continued weakness in this area j
risks potential damage to safety-related equipment with or without a seismic event.
j ENGINEERING (Module 37551,71707) Engineering demonstrated good performance in evaluating, inspecting, and tracking an identified through-wall leak in service water piping.
Although the licensee took adequate corrective actions i
in response to a trip of a service water strainer motor, system engineering i
]
based their root cause determination on unsubstantiated assumptions.
i
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During the inspection period, the inspectors and the licensee identified l
several examples of inadequate problem identification and resolution of deficiencies associated with safety related equipment.
In each of these instances engineering staff knew of the degraded conditions but failed to take timely and appropriate corrective action.
As a result, Salem operators were unaware of conditions with the potential to erode their ability to safely operate the plants.
The quality of applicability reviews and safety evaluations required by 10 CFR l
50.59 continued to be inconsistent. Although some were excellent, others were incomplete, or did not provide sufficient basis to demonstrate that a Unreviewed Safety Question did not exist or that configuration was commensurate with the established design and licensing bases.
PLANT SUPPORT (Module 71707,71750)
The radiation protection department took thorough and appropriate corrective action in response to a procedure i
violation on the part of radiation workers.
Asecuiityguard,inanattempttocorrectadegradedsecuritydoor, denied maintenance personnel the opportunity to perform thorough root cause 1
determination.
SELF-ASSESSMENT AND QUALITY VERIFICATION (Module 71707)
Senior management establishes expectations for performance at Salem. During the inspection period, Salem senior management placed considerable emphasis on improving performance in the areas of planning, event-free operation, maintenance and surveillance, and on ownership and accountability.
The Salem Station Operating Review Committee (SORC) and the senior managers, however, did not systematically and rigorously examine the potential safety impact of degraded conditions and planned activities brought to the SORC and the i
managers' meeting. Senior management identified inadequate planning, but did not consistently identify the nature of the inadequacies or provide clear 1
expectations relative to adequate planning.
In addition, SORC did not 1
adequately review 10 CFR 50.59 safety evaluations or reportable events. The members of SORC did not have a fundamental understanding of 10 CFR 50.59 or NSAC 125, nor did they understand the purpose for reviewing reportable events.
Consequently, the inspectors concluded that Sales senior management had not effectively established or communicated clear standards or expectations relative to critical review and evaluation of matters that affect safety performance. The inspectors also concluded that the inconsistent quality of planning, Licensee Event Reports (LER), and 10 CFR 50.59 applicability reviews and safety evaluations resulted from lack of clearly defined standards for j
performance.
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The inspectors noted two significant examples of contributions to improved plant safety and performance by the Quality Assurance / Nuclear Safety Review 4
(QA/NSR) department. An audit report and a monthly report provided excellent i
review and evaluation of performance issues and indicators relative to Sales and Hope Creek.
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TABLE OF CONTENTS t
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El>C0J1VE
SUMMARY
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TABLE OF CONTENTS............................
iv 1.0
SUMMARY
OF OPERATIONS.......................
1 l
t 1
2.0 0?ERATIONS 2.1 Challenges tc Operators...................
1 i
j 2.2 Service Water Pump Operability 1
l 3.0 MAINTENANCE AND SURVEILLANCE 2
1 3.1 Routine Maintenance Observations 2
3 3.2 Planning Performance 3.3 Control of Maintenance Activities..............
5 i
3.4 Control of Scaffolding in Safety-Related Areas 5
l 3.5 (Closed) Violation (50-272&311/93-23-02); Emergency Diesel j
Generator (EDG) Operability.................
6 l
3.6 Routine Surveillance Observations..............
7 1
3.7 Inadequate Unit 1 Refueling Water Storage Tank Level 7
4 l
4.0 ENGINEERING............................
8 j
4.1 Engineering Assessment of Service Water Strainer Motor Trip.
8 j
4.2 Service Water Pipe Through-Wall Leak 8
4.3 Problem Identification and Resolution............
9 4.4 Evaluation of Changes to the Plant 10 l
l 4.5 (Closed) Deviation No. 50-311/93-82-09, EDG Protection 1
Against Tornado.......................
12
(
5.0 PLANT SUPPORT...........................
13 5.1 Radiol ogical Control s....................
13 14 l
5.2 Security..........................
5.3 Inspection of Fire Damper Upgrade Project..........
14 6.0.
Safety Assessment and Quality Verification 15 i
6.1 Management Oversight of Plant Activities 15 l
6.2 (Closed) Evaluation of Changes to the Salem and Hope Creek i
Site and Environs (TI-2515/112)...............
17 l
6.3 Quality Assurance and Nuclear Safety Review Department 18 1
Contribution to Safety 18 7.0 REVIEW OF REPORTS AND OPEN ITEMS 19 j
7.1 Open Items.........................
20 I
8.0 EXIT INTERVIEWS / MEETINGS l
8.1 P.esident Exit Meeting....................
20 8.2 Specialist Entrance and Exit Meetings............
20 f
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i DETAILS 1.0
SUMMARY
0F OPERATIONS Unit 1 began the period operating at 94% power due to a leak in the no. 13C feedvater heater. The unit remained at this power level until May 4, when operrtors reduced power to 48% for modification of the steam generator feed The unit continued to operate at 485 at the end of the inspection pumps.
period.
Unit 2 began the period at 50% power. Operators reduced power to 50% in response to speed oscillations in the no. 21 main feedwater pump. On April 1, operators increased power to 96% to collect statepoint data. Despite a turbine control valve position limiter problem, operators maintained the unit j
at or near full power for the remainder of the period.
2.0 0PERATIONS The inspectors verified that, overall, Public Service Electric and Gas (PSE&G) operated the facilities safely, but were challenged frequently due to plant performance and equipment reliability problems. The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including 16 hcurs of deep back-shift inspections.
2.1 Challenges to Operators The inspector noted that. equipment deficiencies continued to provide daily l
challenges to control room operators. Previous NRC inspection reports identified degraded conditions, work-arounds and distractions to operators.
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The inspector noted that Unit 1 control room operators endured 13 surveillance l
tests, 8 technical specification entries, 5 abnormal overhead annunciators, and 14 emergent equipment deficiencies during one 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period in early j
i April. Although this may not represent a typical day, Sales operators frequently experience challenges that provide increased risk of personnel error and increased challenge to safe plant operation due to equipment Lu. vallability l
2.2 Service Water Pump Operability During this inspection period, the laspectors noted continued operator focus on identifying and correcting equipment deficiencies in a time frame suitable to its importance to safety.
In response to discussions with the inspectors, operators increasingly questioned how degraded conditions affected the ability l
of a system, sub-system, or component to perform its intended function as l
captured in the design basis. Despite the noticeable improvement in the I
operators' questioning attitude, in several cases operability determinations and safety evaluations still failed to document an established basis for c
conclusions affecting the service water system.
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For example on March 28, maintenance staff removed the no. 15 service water (SW) pump for a bolt inspection. Operations identified increasing packing leakage from the no. 16 SW pump strainer. The operations staff also found water in the oil of the no.14 SW pump. The inspectors noted that the degraded conditions described by operations affected all three SW pumps supplying the no.12 SW header.
In response to inspector questions, the operators declared the no.12 SW header inoperable. The plant staff concluded that completing maintenance of the no.15 SW pump constituted the best path to restoring the no.12 SW header and exiting the Technical Specification 3.7.4.1 action statement.
The inspectors noted a licensee Technical Specification 3.7.4.1 interpretation that required operability of the associated traveling screen and strainer to supp9rt operability of a SW pump. The inspectors also noted that, as a result of instrumentation problems, the traveling screen associated with no.15 SW pump would not automatically start on high differential pressure, and questioned whether operability of the no. 15 SW pump required automatic start of the traveling screen. Subsequently, system engineering concluded that operability of a SW pump did require automatic operation of the associated i
traveling screen and strainer and operations entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement to return one of the three SW pumps to service. Subsequent'y, the maintenance staff repaired the degraded differential pressure instrunnt to restore automatic operation of the traveling screen and completed installation of the no. 15 SW pump to exit the action statement.
The inspectors noted that operations identified the degradet conditions associated with the nos. 14, 15, and 16 SW pumps. However, until challenged by questions from the inspector, the plant staff did not atsess the impact of the degraded SW conditions on operability of the SW header..
3.0 MAINTENANCE AND SURVEILLANCE i
3.1 Routine Maintenance Observations The inspectors observed portions of the following safety-related maintenance to learn if the licensee conducted the activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.
The inspector observed portions of the following activities:
Work Order (WO) or Design MDit Chanae Packaae (DCP)
Description Salem 1 WO 950325237 No. 11 service water pump repair Salem 1 WO 950325239 Verify bolting material,16 service water pump Salem 1 WO 950325237 Verify bolting material,11 service water pump 4
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Sales 2 WO 950404201 SGBD outlet valve diaphragm replacement i
Salem 2 WO 950501266 2A1 28 volt battery charger breaker i
I Salen 2 WO 940809079 No. 23 charging pump flow oscillations 4
Salen 2 WO 950411139 No. 23 service water pump bolt inspection 1
i The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance program.
l 3.2 P1anning Performance During the inspection period, the inspectors noted several examples of less 4
i than adequate maintenance planning. The improper planning resulted in safety j
related equipment not being available if required, and workers performing a significant number of activities under pressure resulting from time limitations. This mode of work put the plant at increased risk of personnel l
error and from unavailable equipment necessary to mitigate the consequences of an accident.
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At 9:20 a.m. on April 4, technicians blocked the output of the control room i
intake duct process radiation monitor (2RIA) to conduct a scheduled surveillance. The 2RIA and 2 RIB instruments cause control room ventilation swap over to " accident inside air" when either monitor senses high radiation l
in the control room intake. On January 27, operators had blocked 2 RIB due to voltage spiking causing spurious actuations. Maintenance completed" repairs j
to 2 RIB in March, but operators maintained it bloc hd to prevent further spurious actuations.
Blocking 2RIA on April 4, reaered the control roon 4
j emergency ventilation system inoperable since it would not automatically swap over if required. At 3:24 a.m. on April 5, when operators recognized that 4
both monitors (2RIA/2 RIB) were in the blocked condition, they placed control i
i room air in the recirculation mode and by 1:00 p.m. on April 6 unblocked both radiation monitors. As a result of the operator work-around for 2 RIB, and
}
since planning did not require technicians to insure that operators unblocked i
2 RIB prior to beginning work on 2RIA, plant staff failed to maintain at least one control room intake duct process radiation monitor operable. This is a violation of the requirements of TS 3.7.6 for operability of the control room i
l emergency air conditioning system (VIO 50- 2721311/95-07-01).
On April 4,1995, Unit 1 operators used 70 hours8.101852e-4 days <br />0.0194 hours <br />1.157407e-4 weeks <br />2.6635e-5 months <br /> of a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS 3.5.2 Limiting Condition of Operation (LCO) for maintenance on the no. 12 charging pump. The licensee planned to complete pump maintenance in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The i
j licensee determined that failure to limit the scope of the maintenance to the original plan, failure to identify all probable causes of identified i
deficiencies, and delays in obtaining parts required to correct deficiencies identified during the maintenance resulted in the delay in returning the pump to service.
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l On April 12, Unit 2 plant staff made inoperable the second of two plant vent noble gas radiation monitoring channels required to permit containment atmosphere purging. Plant staff took the second noble gas monitor channel out 4
of service for planned maintenance. As a result, Unit 2 containment pressure reached 0.33 psig, exceeding the TS 3.6.1.4 limit of 0.3 psig. Technical Specification 3.6.1.4 required that operators reduce containment pressure to j
less than 0.3 psig within one hour, otherwise place the plant in hot standby i
within the next six hours, and in cold shutdown in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Operators began to purge containment to reduce pressure 43 minutes after entering TS 3.6.1.4, successfully reducing pressure below the limit in the time allowed. The licensee had maintained one of the two available channels (plant vent noble gas monitor) out of s?vice (awaiting parts) since November 17, 1994.
On April 13, operators removed the no. 21 charging pump from service to perform planned maintenance. Since the no. 23 charging pump was already out i
l of service, the removal of no. 21 charging pump required presented the l
increased risk of inability to mitigate the consequences of a small break loss i
L of cooling accident. Operators considered this risk; however, the planning department stressed the immediate need to perform pump PM's in accordance with the schedule. System engineering did not identify any pump operability concerns that necessitated an immediate pump maintenance outage. The inspector noted a significant failure to communicate between operations, planning, and engineering.
l On May 4, at 5:01 a.m., plant staff took the IB Emergency Diesel Generator i
(EDG) out of service for preventive maintenance. On May 4, at approximately 7:00 p.m., maintenance staff discovered conditions requiring corrective j
maintenance. As a result, on May 5 operators concurrently ran the IB EDG for post-maintenance testing, and the IC and 1A EDGs to meet the requirements of Technical Specification 3.8.1.lb, action statement b.
The operators maintained at least two of three output bremrs simultaneously closed from 4:19 a.m. until 5:22 a.m.
They initially concluded that.the corrective I
maintenance on the IB EDG required them to demonstrate operability of the 1A and IC EDGs within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the time they first took the IB EDG out of service. Operators subsequently concluded that TS 3.8.1.lb, action b.,
l required them to demonstrate operability of the 1A and 1C EDGs within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the time that the discovery of the degraded conditions requiring corrective l
l maintenance. The inspectors found that the operators and support staff did j
not consider the commitment to Regulatory Guide 1.108 prior to the maintenance l
activity. The commitment, documented the basis for TS 3.8.1.1, requires nonconcurrent testing of EDGs during normal plant operation. Failure to test the EDGs nonconcurrently is a deviation from PSE&G commitments to the NRC.
(DEV 50-2721311/95-07-02)
The inspectors concluded that lack of contingency planning resulted in confusion over the requirements of TS 3.8.1.1.
As a result, operators rushed unnecessarily to perform EDG surveillances. The inspectors observed that the need to hurriedly start the EDGs in a last minute attempt to meet a perceived l
TS requirement posed increased risk of personnel error.
In addition, the l
inspectors considered planning inadequate since it did not incorporate review l
of the regulations and commitments applicable to the EDGs.
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5 3.3 Control of Maintenance Activities j
The inspectors identified two examples of less than adequate control of maintenance activities concerning safety-related equipment. One incident i
involved the licensee's failure to follow prescribed work control procedures, the other is a result of an activity conducted without an approved procedure.
I The fact that these incidents were NRC identified underscored the licensee's inadequate oversight of maintenance.
On April 28, 1995, the inspector observed plant staff draining water from the Unit I refueling water storage tank (RWST) to a floor drain. Operations, with Radiation Protection support, attempted to flush hot spots from safety-injection suction piping. The inspector determined that the activity involved opening a drain connection, located on the common suction header for the two intermediate head safety-injection (SI) pumps. A licensed operator supervised l
the activity, a' shift supervisor approved it, it was controlled by a step-by-step work standard, and reviewed by a cross-disciplinary team.- However, the inspector noted that the workers did not use an approved procedure to control this safety-related process, and the work standard had not been reviewed to evaluate the impact of the draining process on operability of the RWST or the safety injection pumps. The inspector determined that the open drain line t
subjected the two SI pumps to possible air binding, and diverted RWST flow A
from the SI suction. The licensee canceled plans to conduct additional l
i flushing evolutions. At the end of the inspection period, the licensee was still reviewing the safety consequence of the RWST draining evolution. The inspector determined that failure to provide a properly reviewed and approved I
procedure is a violation of Technical Specification 6.8.1 and NC.NA-AP-ZZ-0009. (VIO 50-2721311/95-07-03)
On May 4,1995, the inspector observed reinsta11ation of the no. 23 service water (SW) pump following bolt inspection. The inspector noted that Instrumentation and Controls (I&C) technicians were installing a new SW pump electrical junction box. The inspector noted that technicians had no work order or work package in the field.
The job supervisor was away from the job site discussing a design change package (DCP), needed to support the l
installation of the electrical junction box, with engineering. The technicians had started the junction box installation prior to engineering l
approval of the DCP. The inspectors concluded that the DCP process did not control the installation of the junction box modification, as required.
In l
this case, maintenance used the DCP to document the modification. The i
inspector. concluded that lack of a work order or work package on the job site was an additional example of' failure to comply with the TS 6.8.1 requirement to control work. (VIO 50-272 & 311/95-07-03 pertains).
3.4 Control of Scaffolding in Safety-Related Areas Inspectors identified two failures to properly control scaffolding in safety-related areas as required by NC.NA-AP.ZZ-0023 (NAP-23), Scaffolding and Transient loads Control. The inspector determined that continued licensee weakness demonstrated in scaffolding control risked potential damage to c
safety-related equipment during normal operation.
In addition, the inspector l
noted additional procedure adherence deficiencies.
Inspectors previously r
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identified scaffolding installed with inadequate clearances, improper restraints, inadequate variance inspections, and lack of timely removal in NRC l
inspection report 50-272/95-02. The inspector concluded that the licensee has not adequately addressed weaknesses in scaffolding control.
1 On April 26, 1995, the inspectors identified several discrepancies in the installation of scaffolding adjacent to the no.11 auxiliary feedwater (AFW) i pump.
Inspectors noted that cross bracing, restraints, clearances, and i
required variance did not meet the requirements of NAP-23. The inspectors also noted that the scaffolding touched and compressed the inlet filter for the motor-driven AFW pump room cooler. The inspector observed that the potential existed to render the AFW pumps inoperable independent of postulated l
seismic effects.
In response to inspector observations, maintenance personnel l
promptly removed the scaffolding.
On May 1,1995, the inspector identified a scaffold built in, around, and against containment fan cooler unit service water piping in the Unit 2 i
auxiliary building. The inspector noted that the work requiring the scaffolding had been completed on January 25, 1995. Procedure NAP-23 requires i
that plant staff remove scaffolding in safety-related areas in a timely manner following completion of the maintenance.
In addition, the inspector noted l
i that the required variance form was not properly completed to document the acceptability of the as-built scaffolding given known non-conformance with the NAP-23 guidelines. (VIO 50-272&311/95-07-03 pertains) 3.5 (Closed) Violation (50-272&311/93-23-02); Emergency Diesel Generator i
(EDG) Operability This violation documented that Sales staff periodically isolated an EDG air t
start system for maintenance, relying on the remaining air start system to provide EDG operability. Plant staff had not, however, demonstrated the capability of the EDGs to start on one air start system since plant construction; routine surveillances actuated both air start systems for each EDG to demonstrate operability. As a result of not performing adequate surveillances to demonstrate EDG operability on a single air start system, plant staff failed to comply with the Technical Specification 3.8.1.b i
requirement of EDG operability whenever they isolated an air start system for maintenance.
l In response to the violation the licensee modified the monthly surveillance procedure to require demonstration of EDG operability on each individual air start system at least once per 18 months. They also developed a procedure to require demonstration of EDG ability to start on the unaffected air start system prior to isolating an air start system for maintenance.
)
The inspector reviewed the two procedures, determined they met the requirements of EDG Technical Specifications, and concluded that the licensee took appropriate short and long term corrective actions in response to the
)
violation. This item is closed.
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3.6 Routine Surveillance Observations The inspectors performed detailed technical procedure reviews, observed I
surveillances, and reviewed completed surveillance packages. The inspectors verified that plant staff did the surveillance tests in accordance with approved procedures, Technical Specifications and NRC regulations.
)
l The inspector reviewed the following surveillances:
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Mail Procedure No.
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Salem 1 S1.0P-ST.DG-0005 Diesel generator auxiliaries -
l 12 fuel oil transfer system operability test L
Salem 2 S2.0P-ST.RC-0008 Reactor coolant system water inventory balance 1
Sales 2 S2.0P-ST.AF-0003 Inservice testing - no. 23 j
auxiliary feedwater pump Salem 2 S2.IC-FT-RCP-0068 Containment pressure protection channel II The inspectors observed that plant staff did the surveillances safely, i
effectively proving operability of the associated systems.
f 3.7 Inadequate Unit 1 Refueling Water Storage Tank Level Licensee Event Report (LER)94-015, dated November 17, 1994, and its supplement 94-015-01, dated March 29, 1995, reported less than the minimum I
refueling water storage tank (RWST) level required by Technical Specification (TS) 3.5.5.
The TS requires the RWST to contain a minimum of 364,500 gallons in Modes 1, 2, 3, and 4.
At various time between January 20, 1994 and October 18, 1994, however, with the unit in Modes 1, 2, 3, or 4, the licensee did not i
meet the minimum volume for RWST level due to indication errors. For these times, the licensee failed to declare the RWST inoperable or take the actions required by TS 3.5.5 Action. The licensee discovered the errors on October j
18, following calibration of the level transmitters.
In response, they adjusted the transmitters and subsequently restored level, returning the tank to operable status, i
The Final Safety Analysis Report provides that a minimum RWST volume of 193,000 gallons is needed to ensure there is sufficient water available for injection into the reactor coolant system in the event of a loss of coolant accident. The licensee determined that from January to October, actual RWST j
level was not less than approximately 348,900 gallons. This determination was based on instrument indication errors, instrument uncertainties, and a review of shift logs. Therefore, they concluded the event had minimal safety significance.
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The inspetor reviewed the LER, determined the corrective actions were appropriate, and concluded there was minimal safety significance.
3 3
4.0 ENGINEERING j
4.1 Engineering Assessment of Service Water Strainer Motor Trip 1
l Salem System Engineers issued a meno to the operators that discussed the cause of an April 15 service water strainer motor trip on overload. The engineers concluded that inadequate strainer upper bearing preloading allowed the strainer to wobble slightly, in turn allowing the strainer to rub against its j
backwash arms and wear rings, causing the motor to trip on high current. The inspector noted that while system engineers reached a likely conclusion for i
what caused the motor to trip, they did not provida a basis for assumptions l
used to support their conclusion.
s' Engineering assumed that a strainer motor trip due to rubbing internals would i
i happen shortly after maintenance affecting upper bearing snugness.
In an attempt to support their assumption, engineering reviewed five years of strainer maintenance history.
Due, possibly, to sketchy maintenance documentation the search did not produce data to substantiate engineering's assumption.
4 The engineers also assumed that a correctly loaded upper bearing would result i-in successful strainer performance during a subsequent service water pump performance test. During the performance test, with the strainer in service (rotation) and subjected to full system flow, the engineers postulated that the flow rate could cause the strainer to wobble with inadequate upper bearing i
pre-loading. However, since the strainer design uses balanced flow regardless 4
of flow rate, the connection between system flow and strainer wobble was not i
clear to the inspector. The inspector concluded that engineering did not establish a sound basis for concluding that a pump performance test would expose inadequate upper bearing preloading.
f The licensee's corrective actions included consulting the strainer vendor and determining an appropriate torque value for upper bearing preloading. The 4
licensee established a timetable to check all strainer bearing preloading concurrent with scheduled maintenance. Also, Maintenance updated all strainer work orders and preventive maintenance procedures to include the torque 5
j requirement.
The inspector concluded the licensee initiated adequate immediate corrective actions to address symptoms of the strainer motor trip. However, the l
inspector also considered the engineering assessment of the cause weak because i
it reached a conclusion based on unsubstantiated and weak assumptions.
4.2 Service Water Pipe Through-Wall Leak b
On April 26, 1995, an alert operator discovered a small through-wall leak in the pressure boundary of a 30 inch diameter service water (SW) line in a Unit i
1 SW intake bay. The pinhole leak is located downstream of an intake bay cross-tie valve (12SW17) that connects the two Unit 1 SW pump distribution 5
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headers. The leak rate is limited to 1-2 drops per minute. The licensee performed an ultrasonic (UT) examination of the affected piping and determined that the leak was due to localized corrosion (1-1/2" x 1-1/2" area 'of piping under code minimum wall). Engineering noted that such localized corrosion is typical of the corrosion experienced in lined carbon steel SW pipe at Sales.
The UT results demonstrated that the remaining areas of the pipe wall adjacent to the defect maintained a significant margin above the minimum value.
In addition, engineering performed a stress calculation, and concluded that the l
structural integrity of the SW piping did not present an operability concern.
The licensee dhteresined that the applicable Technical Specification Limiting Condition for Operatic.n did not allow sufficient time to accomplish the ASME code repair at power. Tia licensee implemented the measures required by NRC Generic Letter 90-05, Guidance For Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping, while considering available options to l
j perform a code repair or to use as-is under Generic Letter 90-05 guidance.
l The inspector determined that engineering documentation and calculations appropriately supported the licensee's operability detenmination.
In addition, the timeliness of the evaluation was commensurate with the TS LCO allowed outage time given an inoperable SW header.
The inspector noted good engineering performance as exhibited by thorough calculations and evaluations, detailed examinations and inspections, and in-depth knowledge of ASME code requirements. The inspector determined that licensee actions to address this SW 1eak have been appropriate and fully within the <;uidelines of Generic Letter 90-05.
4.3 Problem Identification and Resolution During the inspection period, the inspectors and the licensee identified several examples of inadequate problem identification and resolution of deficiencies associated with safety related equipment.
In each of these instances engineering staff knew of the degraded conditions, but failed to i
take timely and appropriate corrective action. As a result, Sales operators were unaware of conditions with the potential to erode their ability to safely operate the plants.
The inspectors found the following examples of inadequate or o >
~ ily corrective action for conditions adverse to quality. An oil -
.e laboratory report, dated August 4, 1994, recommended resampling and che s v
.he oil on the no. 21 high-head safety injection pump based upon a ten-n screase in wear concentration. An oil analysis, dated November 28, 1994. mantified high wear particle concentration in the no. 22 high-head safety-inject non pump i
l speed increaser oil. On March 20, 1995, the responsible system engineer issued Equipment Malfunction Identification System (EMIS) tags on the above 4
components identifying the degraded conditions. Additionally, a lab report, dated October 6,1994, recommended resampling the no. 23 AFW turbine lube oil i
i due to a trace amount of water found and a marked increase in wear l
concentration particles. On March 27, 1995, the system engineer issued an EMIS tag addressing this degraded condition. The inspector noted that the j
engineer had little or no documentation on the above problems other than the initial lab reports.
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l 10 On April 18, 1995, the inspectors discussed the above concern with licensee management. At the end of the inspection period, the inspector was still i
awaiting response from engineering concerning sampling or changing of the oil, the root cause determination, and the present oil condition for the related systems.
i In May 1994, a system engineer initiated a work request to inspect the 2A1 28 l
VDC battery charger ground detection circuit (GDC) wiring. He initiated the
{
request following a system walk-down of the 28 V battery chargers that revealed Unit I chargers were configured differently than Unit 2 chargers.
i However, the work order to conduct the charger internal inspection did not occur until late April 1995. The inspection results confirmed that the GDC was installed (contrary to the vendor's shipping document) and wired in accordance with the schematic. Because the wiring of the GDC presented an
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unaddressed configuration problem, the engineer initiated an incident report (IR).
In response to the IR, the Nuclear Engineering department evaluated the effect of the GDC on the charger and determined the charger was still 1
Engineering also initiated a design change package to remove the wiring on the charger, as well as on the other three chargers if installed.
Finally, the licensee inspected the four Unit 128 VDC chargers and determined i
the GDC was not installed.
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Licensee Event Report (LER) 95-05 identified seven instances of vendor-1.
identified information that indicated that the pressurizer code safety valves l
(PSVs) were out-of-tolerance. The report stated that, between May 8, 1990 and January 14, 1995, the vendor identified that the PSVs did not meet the 1%
l tolerance required by Technical Specification 4.0.5 requirement for Salem Unit l
1.
The LER further stated that the four instances between November 14, 1994 i
and January 14, 1995 each identified that two of the installed three PSVs did l
not meet the TS 4.0.5 tolerance requirement.
In each case, the vendor notified the appropriate system engineer by telephone, and followed the i
telephone report with a written report.
In all cases, the Salem personnel who 1
were informed by the vendor of the out-of-tolerance condition failed to l
initiate an Incident Report. As a result, PSE&G did not initiate timely root cause or reportability evaluations. This is an apparent violation of the l
requirements of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action".
4.4 Evaluation of Changes to the Plant l
The inspectors reviewed two safety evaluations and one applicability review to determine whether they met the requirements of 10 CFR 50.59. The j
j applicability review for safety evaluation S-1-SW-MSE-0847, Salem Unit 1 l'
Service Water Pump Fastener Material (Colunn-to-Discharge Head), dated 3/25/95, appropriately identified that use of stainless steel fasteners in l
place of the required Monel fasteners constituted a change to the plant as described in the Updated Final Safety Analysis Report (UFSAR).
]
The engineers performing the safety evaluation clearly identified the support i
function of the fasteners required to enable the service water pumps to perform their intended function. The engineers further described the form, j
fit and function of the fasteners, and the conditions under which the fasteners performed their function, including stress and corrosion. The t
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safety evaluation appropriately concluded that though the required Monel
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fasteners were inadvertently replaced with stainless steel fasteners the condition did not pose a short term threat to service water pump operability.
i The inspectors noted that the safety evaluation clearly described the aspects of the stainless steel fasteners differing from the Monel fasteners, and the j
effects of the differences on the design basis requirements for the fasteners.
Finally, the safety evaluation provided a basis for concluding that, for a j
period of 60 days, the stainless steel fasteners met the design basis requirements for service water pump fasteners.
l The inspectors considered the conclusion of the safety evaluation appropriate.
In addition, the inspectors found that the engineers had developed a well-organized, understandable safety evaluation. The engineers applied a logical approach to problem solving founded in the plant design basis and the application of 10 CFR 50.59.
The inspectors also reviewed a 10 CFR 50.59 applicability review, JA-125VDC j
Battery Cell No. 35 Post Sea 7 Degradation, dated April 7, 1995, in response to Deficiency Report (DR) 950406124. The review stated that a 3/4 inch piece of j
scavenger post seal lead had broken loose from the positive post seal of IA-l 125VDC battery cell no. 35 and landed on top of the adjacent plate separators around the sixth positive plate from the left. The manufacturer stated that i
electrolyte intrusion corroded the scavenger post seal to prevent corrosion of the current carrying post. The.cyaluation stated that the fallen piece was i
not long enough to short between two adjacent plates. The evaluation further stated that, according to the manufacturer, post seal deformation, first j
observed in August 1994, was a long term slow moving condition that was not a l
service affecting condition. The manufacturer further stated that post seal i
deformation was controllable with normal maintenance. The evaluation stated that the system manager (formerly called the system engineer) will continue to monitor the condition and will intensify the weekly battery surveillance l
visual examination. Based on these findings, the engineer found a "use-as-is" i
disposition acceptable for DR 950406124.
l The inspectors found that the evaluation of post seal degradation i
inappropriately concluded that the condition did not change the plant as i
described in the Updated Final Safety Analysis Report (UFSAR) since the battery cell post seal design details were not described.
In reaching this i
conclusion, the evaluation failed to consider the potential effect of battery cell failure on the ability to mitigate the consequences of an accident. The i
evaluation also failed to consider that the UFSAR described the 125VDC j
battery.
In addition, although the evaluation stated that the purpose of the l
scavenger post seal was to prevent corrosion of the current carrying post, the evaluation did not clearly assess the effect of loss of scavenger post lead on i
}
the current carrying post. Further, the evaluation did not address the cause i
of the post seal degradation, or the basis for concluding that it did not constitute a service affecting condition. The failure to adequately i
demonstrate that the effects of post seal degradation did not constitute an i
unreviewed safety question is a violation of 10 CFR 50.59. (VIO 50-272&311/95-
{
07-04) t; 4
i
12 The inspectors reviewed the safety evaluation associated with DR 950314167, 22 R## Room Cooling Notor, dated 4/3/95.
In 1989, maintenance replaced the motor for the RHR fan cooler with a service water intake (SWI) area exhaust fan motor.
Plant staff performed the replacement as corrective maintenance for the failed motor. Though the engineers referenced the stated design requirements of the RHR room cooling motor throughout the safety evaluation, they did not clearly address the differences between the motors in terms of size, weight, shape, and method of mounting the RHR room cooler. The safety evaluation stated that the seismic requirements of the SWI area were much more severe than the RHR room cooler location, therefore they concluded that the replacement motor was fully qualified for the RHR room cooler location. The evaluation did not address the effect of installing a motor of (perhaps) different size and weight on the seismic qcalification of the room cooler.
The evaluation also stated that the design of the RHR fan cooler motor requ; red environmental qualification. The vendor had qualified the SWI motor for a mild environment, however, the RHR room cooler required qualification for a harsh environment consisting of exposure to radiation. The evaluation concluded that, since the licensee planned to replace the fan in the fall of 1996, the motor would not be subjected to radiation in excess of its permissible dose. The safety evaluation did not state if the basis for this conclusion incorporated the effects of accident induced radiation prior to the 1996 replacement.
In addition, the evaluation stated that the motor replacement did not increase the consequences of an accident, since the plant 1
staff had installed the SWI motor in only the 22 RHR room cooler and the redundant train of RHR remained available to mitigate the consequences of an i
accident. The evaluation determined that the SWI exhaust fan motor required 2200 feet per minute air flow past the motor for cooling. Due to physical J
configuration, only 500 CFM air flow was available to the motor as installed i
in the RHR room cooler. The evaluation concluded that reduced air flow resulted in elevated winding temperatures leading to shortened motor life.
However, the evaluation concluded that, despite the elevated temperatures i
under worst case conditions, the remaining service life provided reliable -
i motor operation until the planned replacement in 1996.
j The inspectors determined that the safety evaluation did not adequately document a basis for concluding that seismic and environmental qualification of the SWI motor did not affect operability of the RHR room cooler. The inspectors also found that reliance on redundant trains of safety related equipment did not form a basis for determining that use of the SWI motor did not increase the consequences of an accident previously identified in the UFSAR.
In addition, plant staff did not evaluate the effects of the change prior to installing the motor and considering RHR operable. This is an i
additional example of a violation of 10 CFR 50.59. (VIO 50-272&311/95-07-04 pertains).
4.5 (Closed) Deviation No. 50-311/93-82-09, EDG Protection Against Tornado l
This deviation identified deficient protection against the effects of a tornado and tornado-generated missiles for the Unit 2 emergency diesel generator (EDG) combustion air exhaust pipes and intake louvers.
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13 The licensee did not dispute this deviation as discussed in their response 1
j letter, dated January 6, 1994. The licensee implemented design change package (DCP) No. 2EC-3286, Revision 0, " Diesel Generator Combustion Air Modification" during refueling outage eight (October 1994). This modification truncated the l
EDG exhaust piping on the auxiliary building roof, added a protective barrier shell of larger diameter reinforced pipe around each exhaust line, added a concrete structure for the exhaust pipes as a barrier for large tornado l
j missiles, and added a tornado missile proof concrete labyrinth barrier around j
the louvers at the EDG air intake opening.
l i
l The inspector reviewed the DCP Design Analysis, referenced calculation S-C-DG-i MDC-0857, Revision 0, "EDG Combustion Air Intake and Exhaust Pressure Drop,"
i and walked down the installed modification. This review was made to verify the adequacy of the changes for providing tornado protection. The inspector verified that the pressure drop calculation for the modified EDG combustion air path was acceptable. This air path was for the EDG intake air through the i
louvers located on the side of the auxiliary building.
Results of the l
calculation indicated that the pressure drop was not increased and remained j
within EDG design limits with the installation of the concrete barrier. The inspector verified that the installed configuration matched the DCP and that the licensee installed these barriers in accordance with the seismic and i
j tornado protection requirements as described in the updated final safet9 l
analysis report (UFSAR) section 3.5.2.1 and NRC Regulatory Guide 1.117,
]
Revision 1, " Tornado Design Classification."
l l
Based on review of the DCP, sepperting calculation, and verification of the installed configuration, the in;pector concluded adequate measures had been f
taken to assure tornado and tornado missile protection for the EDGs. The licensee stated that although Unit I was not committed to NRC Regulatory Guide 1
l 1.9, " Selection, Design, and Qualification of Diesel Generator Set Capacity for Standby Power Supplies" or Regulatory Guide 1.117, the same modifications implemented on Unit 2 were planned for implementation on Unit I during the next scheduled Unit 1 outage. This item is closed.
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5.0 PLANT SUPPORT i
5.1 Radiological Controls On March 24, four PSE&G employees working under radiation work permit (RWP)-
95-05-0005-0 violated the requirements of the RWP by entering the Unit 1 safety injection (SI) pump room, posted as a high radiation area (HRA).
The j
RWP clearly stated "no entry into HRAs." Radiation Protection (RP) technicians had surveyed the SI pump room before and after the inappropriate j
entry and found that it was no longer a high radiation area. They had not re-i
. posted the area prior to entry by the four workers. The workers did not j
receive any significant exposure from the SI pump room entry.
4 l
The RP staff initiated a radiological occurrence report (ROR) in response to the problem. The investigators concluded that RP technicians had not j
effectively communicated posting of the work area and neglected to question i-the workers about the RWP they would use. The investigators also concluded that two of the workers had less than adequate familiarity with the I
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14 requirements of the RWP, and two of the workers believed that the RP technician had authorized overriding the requirements of the RWP that prohibited entry into HRAs. Short term corrective actions included review of the event with RP department personnel, appropriate corrective training for the workers, and sharing the lessons learned from the event with all Sales and Hope Creek personnel. Although failure to comply with the HRA posting is a requirement of RWP-5 requirements, the violation will not be cited since it was not intentional, could not have been prevented by corrective action from a previous violation, and the licensee took appropriate immediate and long tern corrective action.
5.2 Security On April 18, the inspector discovered that a security door providing access control required by the Sales security plan had malfunctioned. Shortly after the malfunction, a security guard arrived to provide access control to compensate. The guard subsequently restored the door to what appeared to be normal working condition. The inspector noted that the guard did not have training in maintenance activity, and did not use a work order or a procedure to control the maintenance activity, as required by NC.NA-AP.ZZ-0009 (NAP-9).
This is an addition violation of the TS 5.8.la and NAP-9 requirement to control maintenance activities described in section 3.3 above.
(VIO 50-272 &
311/95-07-03 pertains).
5.3 Inspection of Fire Damper Upgrade Project In January 1995, PSE&G completed an extensive fire damper upgrade project for both units. The project included installation of ductwork, new dampers, and ductwork supports.
The inspector reviewed the project document and several modification concern resolutions (MCR) because of questions concerning how some welds were made and h w certain dampers were oriented. The inspector determined that ductwork welds were typically a continuous, seal weld. However, several MCRs authorized an alternative to this method in areas where there was interference with retaining angles and new dampers.
In these examples, the MCRs specified spot welds, with fire-grade sealant used to fill in the seams between spot welds. The inspector also discussed with the Installation Engineer an example where a damper appeared to have been installed backwards. However, as explained in a memo from the vendor to PSE&G, the damper was seismically and fire rating qualified for installation in forward or reverse airflow condition and regardless of location of the fire zone or regardless of whether horizontally or vertically mounted.
In addition, arrows placed on dampers 1
were provided for installation guidance in the field and did not denote airflow direction or fire zone. The inspector concluded, based on a field review of dampers,_ review of the project document, and discussion with the Installation Engineer, that the licensee complied with the installation requirements for ductwork and dampers.
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L 6.0 Safety Assessment and Quality Verification 6.1 Management Oversight of Plant Activities i
The inspector's confirmed PSE&G's intent that senior management establish expectations for performance at Sales. During the inspection period, Salem senior management placed considerable emphasis on improving performance in the areas of planning, event-free operation, maintenance and surveillance, and on ownership and accountability.
The Salem Station Operating Review Committee i
(SORC) and the senior managers, however, did not systematically and rigorously examine the potential safety impact of degraded conditions and planned activities brought to the managers' meeting and SORC. Senior management identified inadequate planning, but did not consistently identify the nature of the inadequacies or provide a clear picture of the qualities i
necessary for adequate planning.
In addition, SORC did not adequately review 10 CFR 50.59 safety evaluations or reportable events. The members of SORC did not have a fundamental understanding of 10 CFR 50.59 or NSAC 125, nor did they understand the purpose for reviewing reportable events.
The inspectors concluded that Sales senior management had not established standards or expectations for nuclear safety performance for itself or for SORC. As a result, the senior maagement team could not monitor its own safety performance. The inspectors also concluded that the inconsistent quality of planning, LERs, and 10 LFR 50.59 applicability reviews and safety evaluations resulted from lack of clearly defined standards for performance.
l On April 19, the inspector attended SORC review of the 10 CFR 50.59 safety evaluation of the use of a service water intake (SWI) area exhaust fan motor in place of a failed 22 RHR room cooler motor. The SORC members did not have clear expectations for the elements of an acceptable safety evaluation.
Members of SORC questioned the basis for concluding that the lack of sufficient air flow did not effect operability. The 50RC members did not identify, however, that the safety evaluation inadequately addressed seismic and environmental qualification. The SORC members did not challenge the reliance on the redundant train of RHR in concluding that use of the SWI motor t
did not increase the consequences of an accident previously identified in the UFSAR. Finally, the SORC members did not discuss that installation of the SWI l
fan motor in 1989 constituted an uncontrolled modification, nor did they identify a need for corrective action as a result of the uncontrolled I
modification. Based on discussions following the 50RC meeting, the inspector determined that SORC did not clearly understand the requirements of 10 CFR 50.59, did not appear familiar with NSAC 125, nor had PSE&G management established clear expectations for SORC review of safety evaluations.
The inspector attended SORC review of draft LER 95-04, Containment Temperature Monitoring. The members of SORC discussed various aspects of the differences between the requirement for measuring average containment air temperature specified in Technical Specification 4.6.1.5, and the method specified by Salem procedure. After lengthy discussion, the SORC tabled the LER with assigned action to obtain further information. The inspector found that 50RC members did not have clear guidance on the purpose for SORC review of LERs, nor did they understand how to determine adequacy of an LER. The SORC members
s i
i indicated that they reviewed LERs to meet the TS 6.5.1.6.g requirement to review reportable events, and the TS 6.5.1.1 requirement to advise the Salem i
General Manager on matters of safety significance. Although SORC discussed safety significance of compliance with TS 4.6.1.5, they did not have a basis for reaching a conclusion or determining a recommendation. The 50RC expected to determine whether they could recommend approval of the LER, but they were i
not familiar with available guidance on LERs, such as NUREG 1022 and its i
supplements, nor did they recognize that the requirer.ents in 10 CFR 50.9 to furnish complete and accurate information to the FRC applied to their LER i
review.
Based on observation of the SORC review of the safety evaluation and the LER described above, the inspector concluded that' despite considerable effort, SORC did not effectively contribute to plant safety. The lack of SORC effectiveness resulted, in part, from lack of management established standards for SORC review.
On April 27, the inspector noted several recent problems with Service Water (SW) requiring corrective maintenance. The recent problems documented in Incident Reports (IR) included:
(
shipping bolts found installed in unit 2 SW spring can hangers (IR 95-300);
no. 3 SW bay inoperable due to water in the oil of 14 SW pump, a bolting e
inspection on 15 SW pump, and 16 SW pump inoperable for excessive strainer packing leakage (IR 95-301);
unit 2 SW strainers causing SW pump packing failures (IR 95-344);
a-a unit 1 SW valve (ISW199) installed incorrectly (IR 95-352);
e incorrect stud material installed in the 13 SW pump discharge expansion e
joint (IR 95-363);
no 13 SW pump traveling screen supply breaker overloads found tripped e
(IR95-380);.
no.13 SW pump strainer supply breaker trip (IR 95-411);
e the no. 21 SW intake ventilation exhaust fan damper solenoid did not e
match design drawing 291461 (IR 95-449);
no. 24 SW traveling screen failed to auto-start (IR 95-452);
e ASME piping leak between 11SW17 and 12SW17 (IR 95-468);
bolting for valve 21SW99 not the required material (IR 95-477); and e
supply breaker problem with 14 SW pump (IR 95-479).
The QA report for Sales for March 1995 also noted a trend of increasing problems with Service Water strainers.
4 At the managers' meeting, the inspector expressed a concern with the reliability of the Service Water systems.
In response, the management team directed that the SW system engineer brief the managers the following day.
The management team required a five minute brief on the system engineer's assessment of whether the condition of the Service water system had degraded.
Coincident with the inspector's :tatement of concern ti.e Nuclear Business Unit (NBU) President and Chief Nuclear Officer expressed concern with SW reliability.
In response, the Salem management team initiated a multi-disciplinary team to evaluate the condition of the Service Water system.
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On April 28, the system engineer told the managers that he did not believe that the condition of the Service Water system had degraded. The engineer and his supervisor told the managers that they believed the increase in documented degraded conditions did not reflect an actual increase in degraded conditions.
The change resulted from increased sensitivity to the requirements to document, investigate, and correct degraded conditions. The system engineer did not offer a basis for his conclusions, and the management team did not question the basis for his conclusion. When the management had apparently l'
finished with topic of Service Water, the inspector questioned the system engineer's basis for his conclusions. The system engineer stated that he had not reviewed documentation and could not furnish data to support his assessment of the Service Water system reliability. The inspector later learned that the system engineer had been instructed that it was not neces u ry to prepare for the managers' meeting. The inspector concluded that, especially in view of the importance of the service water system to mitigating the consequences of an accident, the Salem managers did not adequately examine the condition of the SW system.
The management team has not rigorously and systematically examined the safety consequences of degraded plant conditions or questioned the safety impact of planned evolutions. The management team did not question the condition of the Service Water system until the NBU President and the inspector expressed In response to the expressed concerns, the management team allotted concern.
only five minutes to examine the SW system condition.
6.2 (Closed) Evaluation of Changes to the Sales and Hope Creek Site and Environs (TI-2515/112)
The inspectors reviewed the PSE&G program to identify and evaluate changes in the area immediately surrounding the site containing Sales and Hope Creek nuclear power plants. The PSE&G Emergency Preparedness (EP) organization monitors changes in demography for the area surrounding the site for effects on the ability to evacuate the public in an emergency. The EP staff monitors changes in nearby transportation routes and places of employment, also for potential effects of area evacuation. The licensee does not monitor the area surrounding the site for changes with the potential for affecting plant operation. Emergency Preparedness does not compare population changes with the predictions of the Final Safety Analysis Report (FSAR), nor does PSE&G monitor changes in use of the exclusion area. The EP organization monitors changes in transient population and in the availability of major transportation routes. The licensee does not monitor for construction of gas or oil pipelines, nor for hazardous material processing or manufacturing near the site. Although PSE&G monitors the presence of detritus (marsh grass) in the Del ware River, they do not monitor the rfver for other potential affects on availability of cooling water.
The licensee does not monitor geological, seismological, or meteorological changes affecting Sales and Hope Creek or the surrounding areas.
In summary, the Emergency Preparedness is the only PSE&G organization monitoring changes to the area surrounding the site. The EP organization monitors changes for their effect on evacuation capability, but no PSE&G organization evaluated the changes for other than the effect on evacuation, n
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18 and no process exists for such evaluation. The inspectors noted that, with the exception of changes associated with increased population, no changes have occurred in the area immediately surrounding Salem and Hope Creek.
6.3 Quality Assurance and Nuclear Safety Review Department Contribution to Safety During the inspection period, the inspectors noted two significant examples of contributions to improved plant safety and performance by Quality Assurance (QA) and Nuclear Safety Review Department staff. The QA mechanical maintenance audit (95-142), dated March 25, concluded that the site staff
~ effectively implemented the mechanical maintenance programs for Sales and Hope Creek.
The report also identified poor supervisory oversight of maintenance at Salem and Hope Creek.
In addition, the audit identified a need for improved clarity of Salem work instructions, and at Hope Creek, instances of incorrect material supplied for jobs and procedural noncompliance. The audit further concluded that Hope Creek strengths included work practices, correct tool availability, and communication. The audit concluded that Salem work practices were a strength. The report concluded that additional Hope Creek management attention was warranted to insure the presence and adequacy of work instructions during maintenance, and to improve control of welding activities.
The report also found that additional Sales management attention was needed to improve work scheduling and adherence to work schedules.
The inspectors also reviewed QA/NSR monthly report for March 1995 (NQS95-055). The report identified a need for continued emphasis on initiating Incident Reports at Hope Creek, and the occurrence of several safety tagging problems at both stations. The monthly report identified improvement in Sales control room activities and a number of specific examples of a need for improved Salem performance in the areas of operations and maintenance. For example, the report identified an increasing trend of service water strainer failures and weak associated interdepartmental problem solving in addressing the trend. The report also identified satisfactory Hope Creek operator performance, with weaknesses pertaining to the high volume of telephone calls, and a problem with ' operator procedure adherence relative to shutdown cooling.
As with the maintenance audit report, the monthly report contained detailed information to support the performance observations.
Based on a review of the maintenance audit report and the monthly report, the inspectors concluded that the QA and NSR department findings identified legitimate non-trivial performance problems that occurred during maintenance activities. The inspectors noted that QA reports represented a significant improvement in performance based observation by QA and NSR staff.
7.0 REVIEW 0F REPORTS AW OPEN ITEMS The inspectors reviewed the Salem Monthly Operating ' Reports for February and March for accuracy and content, and found them acceptable. The inspectors also reviewed the following Licensee Event Reports (LERs) to learn whether the licensee took the corrective actions stated in the report, and to detect if the licensee responded to the events adequately, met regulatory requirements conditions, and commitments:
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i 19 Salem Unit 1 Number Event Date Descrintion i
LER 95-001 February 1, 1995 TS 3.0.3 Entry: Both trains of solid state protection system inoperable LER 95-002 February 24, 1995 Failure to restore automatic control of pressurizer power foperated relief valve (PORV) t l
IPR 2 or close associated block l
valve IPR 7 within one hour.
LER 95-003 February 28, 1995 Technical Specification (TS) 3.0.3 entries to support correction of analog rod position indication (ARPI).
LER 95-005 May 8, 1990 Repeat occurrences (both units) of pressurizer code safety valves exceeding lift settings.
(Licensee failure to issue report per 50.73 is a violation, section 3.2)
- Salem Unit 2
)
LER 95-001 February 12, 1995 Manually initiated engineered safety feature actuation to effect a main steam isolation signal in order to increase reactor coolant system T-average above 541 degrees.
LER 95-002 March 11, 1995 TS 3.0.3 entries to support correction of ARPI l
The inspectors determined that the LERs listed above did not identify any violations beyond those previously identified in NRC Inspection Reports, and considered the LERs closed.
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l 7.1 Open Items The inspector reviewed the followirg previous inspection items during this inspection. These items are tabuiated below for cross reference purposes.
Number Report Section Status l
VIO 272&311/93-23-02 3.5 Closed j
DEV 311/93-82-09 4.5 Closed i
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8.0 EXIT INTERVIEWS /NEETINGS i
8.1 Resident Exit Meeting l
The inspectors met with Mr. J. Summers and other PSE&G personnel periodically i
and at the end of the inspection report period to summarize the scope and i
j findings of their inspection activities.
l Based on NRC Region I review and discussions with PSE&G, it was determined i
that this report does not contain infomation subject to 10 CFR 2 i
restrictions..
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8.2 Specialist Entrance and Exit Neetings Inspection Reporting i
Date(s)
Subiect Report No.
Insoector j
3/13-17/95 Engineering 50-272 and 311/95-06 Chaudray i
4/10-14/95 Operator 50-272 and 311/95-08 Bissett Requalification a
5/1-19/95 Effectiveness of 50-272 and 311/95-80 Eselgroth Licensee Controls
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'g NUCLEAR REG T
Y COMMISSION
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'l REGION 1 4
475 ALLENDALE ROAD KING OF PRUSSIA PENNSYLVANIA 194061415
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4 gg g EA No. 95-62 i
Mr. Leon R. Eliason President and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
SALEM RESIDENT INSPECTION NOS. 50-272/95-10; 50-311/95-10
Dear Mr. Eliason:
L The enclosed report documents an inspection for public health and safety, l
conducted by Mr. C. Marschall, Senior Resident Inspector and.other members of 4
the NRC resident and regional staff at the Salem Nuclear Generating Station.
The report covers the period between May 7, 1995 and June 23, 1995. The i
inspectors discussed the findings of this inspection with Messrs. J.* Summers, General Manager-Salem operations, and other members of your staff in an inspection exit meeting on June 23, 1995. These apparent violations (as l
described in the Appendices) were discussed between Messrs. Joseph Hagan, Vice j
President-Nuclear Operations, Mr. Jeffrey Benjamin, Director-Quality Assurance and Nuclear Safety Review, and Mr. John White of our office on July 11, 1995.
4 During this period, Sales management and staff continued t'o demonstrate j
significant weakness in performing operability determinations for degraded,
safety-related equipment, and implementing prompt and effective corrective j
actions. Two of these latest examples involved degraded equipment affecting L
switchgear ventilation equipment in Unit 1, and. residual heat removal (RHR) i minimum flow recirculation valves in Unit 2.
In these cases, your staff j
failed to respond promptly when component failures affecting these systems were first identified in December 1994 and January / February 1995, respectively. Even after it became more imperative to address these component
-issues, your staff delayed operability decision-making until it was apparent that a basis could not be established to justify continued operation.
j Subsequently, the units were shutdown in accordance with license requirements on May 16 and June 7,1995, respectively.
4 Additionally, ineffective corrective actions, due to previously deficient root cause efforts, continue to be identified as equipment problems recur. For l
example, the previous repetitive failures of jacket water instrument lines on one or more emergency diesel generators were not effectively diagnosed as to cause; and previous observations of anomalous noise from RHR system valves (RH-10) were;not evaluated relative to potential safety impact.
In these cases, your organization accommodated the conditions without effective root cause assessment or understanding of the nature'of the problems since 1992.
These latest examples of poor operability decision-making and corrective action ineffectiveness appear to be similar in nature to your organization's j
approach to problem resolution that failed to effectively resolve degraded equipment issues and deficient conditions that were factors in previ~ous events i
such as: the Unit 2 turbine-generator failure in November 1991, caused, in AW
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Leon R. E11ason 2
part, by your organization's delay of planned maintenance and failure to l
resolve abnomal equipment performance response; the. multiple rod control j
system failures during Unit 2 start-up in May 1993, caused by your organizati on's failure to understand the nature and reason for the abnormal i
system response; and the Unit 1 plant trip in April 1994, the recovery from l'
which was exacerbated, in part, by multiple operator work-arounds that were l
willingly accommodated by your organization without resolution.
e In view of the numerous other examples of your failure to properly respond to, and effectively correct, degraded safety-related systesi performance (brought j
to your attention in previous NRC Inspection Reports 50-27?.[311]/95-02and95-07), and the inadequacy of your actions to promptly resolve known technical issues associated with the pressurizer overpressure protection system i
(identified in NRC Inspection Report 50-272[311]/94-32), we question your j
willingness and ability to promptly and critically assess anomalous
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conditions, suspect component reliability, or other degraded equipment issues.
From our perspective, your organization has demonstrated a proclivity to avoid i
prompt problem resolution, and operability ~and corrective action decision-making, by failing to process emergent issues in accordance with your j
established procedures in a timely manner, subjecting the matters to lengthy analysis and indeterminate conclusion, or attempting to justify continued i
operation with insufficient basis. Further, your approach to operability decision-making is often biased toward a positive determination without i
reference to, or consideration of, the applicable design basis, i
Consequently, the matters describcd in Appendix A are being considered for j
escalated enforcement action (in addition to other matters brought to your attention in previous inspection reports) in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement i
Policy), (60 FR 34381; June 30, 1995). Accordingly, no Notice of Violation is i
presently being issued for these inspection findings. The number and characterizaticr. of apparent violations described in Appendix A and the enclosed inspection report may change as a result of further NRC review.
A predecisional enforcement conference to discuss these apparent violations has been scheduled for July 28, 1995. This conference will be closed to public observation. The decisi(n to hold a predecisional enforcement conference does not mean that the NRC has determined that these violations have occurred or that enforcement action will be taken. This conference is being held to obtain information to enable the NRC to~ make an enforcement decision, such as a common understanding of the facts, root causes, missed opportunities to identify the apparent violations sooner, corrective actions, significance of the issues and the need for lasting and effective corrective action. You should also be prepared to address our concerns about your performance as characterized in this letter.
In addition, this is an opportunity for you to point out any errors in our inspection report and for you to provide any infomation concerning your perspectives on 1) the severity of the violations, 2) the application of the factors that the NRC considers when it determines the amount of a civil penalty that may be assessed in accordance with Section VI.B.2 of the Enforcement Policy, and 3) any other application of the Enforcement Policy to this case, including the exercise of discretion in accordance with Section VII. You will be advised by separate e
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Leon R. Eliason 3
. correspondence se results of our deliberations on this matter. No j
response regaramg the apparent violations.is required at this time.
1
)
Based on the findings of this inspection, the NRC determined that violations of NRC requirements occurred. These violations are cited in Appendix B, l
Notice of Violation (Notice). The circumstances surrounding these matters are described in detail in the subject inspection report. The violations are of j
concern because these matters indicate continuing weaknesses relative to 3
i control of maintenance activities and procedural adherence.
4 You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response.
In your i
response, you should document the specific actions taken and any additional actions you plan ~ to prevent recurrence. Your response may reference or
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include previous docketed correspondence, if the correspondence adequately addresses the required response. After reviewing your response to this 4
Notice, including your proposed corrective actions and the results of future i
inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
The responses to the apparent violations described in Appendix B and the enclosed inspection report are not subject to the clearance procedures of the Office of Nanagement and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96.511.
In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosure will be placed in the j
NRC Public Document Room.
a Your cooperation with us is appreciated.
f Sincerely, l
d,%h W l Richard W. Cooper II, irector Division of Reactor Projects i
I Docket Nos. 50-272 1
50-311 i
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Enclosures:
Appendix A, Apparent Violations Considered for Escalated Enforcement l
1.
Action 2.
Appendix B, Notice of Violation 3.
NRC Inspection Report Nos. 50-272/95-10; 50-311/95-10
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Leon R. Eliason 4
cc w/encis:
l J. J. Hagan, Vice President-Operations E. Simpson, Senior Vice President - Nuclear Engineering and Plant Betterment C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
General Manager - Information systems & External Affairs J. Summers, General Manager - Salem Operations J. Benjamin, Director - Quality Assurance & Safety Review l
F. Thomson, Manager, Licensing and Regulation R. Kankus, Joint Owner Affairs A. Tapert, Program Administrator R. Fryling, Jr., Esquire M. Wetterhahn, Esquire P. MacFarland Goelz, Manager, Joint Generation Atlantic Electric Consumer Advocate, Office of Consumer Advocate William Conklin, Public Safety. Consultant, Lower Alloways Creek Township l
Public Service Commission of Maryland l
State of New Jersey l
State of Delaware 1
i
5 Mr. Leon R. Eliason Distribution w/enels:
Region I Docket Room (with concurrences)
Kay Gallagher, DRP Nuclear Safety Information Center (NSIC)
D. Screnci, PA0 (2)
NRC Resident Inspector K. Kolaczyck, DRS (section 2.1)
L. Scholl, DRS (section 2.1)
PUBLIC Distribution w/encis: (Via E-Mail)
L. Olshan, NRR W. Dean, OEDO J. Stolz, PDI-2, NRR M. Callahan, OCA Inspection Program Branch, NRR (IPAS) e l
. _ _. _. ~. _ _. _. _ _. _..... _ - _.
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APPENDIX A APPARENT VIOLATIONS CONSIDERED FOR ESCALATED ENFORCEMENT ACTION l
l 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part, l
l that licensees shall promptly identify and correct conditions adverse to quality, and for significant conditions adverse to quality, the licensee shall also determine the cause, take action to preclude repetition, document the l
corrective action, and notify appropriate levels of management.
Contrary to the above, the Sales staff did not promptly identify, correct, determine the cause, notify appropriate levels of management, or initiate corrective action to preclude recurrence for the following conditions.
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e A.
From January 26, 1995, for the 22 RHR pump minimum recirculation flow valve and from February 9, 1995 for the no. 21 RHR pump minimum recirculation flow valve, until June 7,1995 plant staff failed to correct or determine the cause of the failure of the valves to i
automatically open on low RHR flow as required to prevent RHR pump failure. As a result, both trains of RHR for Salem Unit 2 were i
inoperable from February 9, 1995 until June 7, 1995.
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l B.
From December 12, 1994 until May 16, 1995, plant. staff failed to correct l
or determine the cause of failure of the no.12 safety related switchgear ventilation supply fan. As a result from December 12, 1994 until May 16, 1995, the licensee operated Salem Unit.I with a safety related electric power system incapable of withstanding a single' failure and. continuing to perform its intended function.
C.
On March 6,1995, May 3,1995, and May 8,1995, the Salem Unit I staff failed to correct, determine the cause, or prevent recurrence of failure of the Containment 100 foot elevation personnel airlock to pass its local leak rate test. As a result, from March 6,1995 until May 8, 1995, the containment boundary was incapable of withstanding a single failure and continuing to perform its intended function.
D.
From February 29, 1992 until June 7,1995, Salem Unit 1 staff failed to correctly determine the cause or take action to preclude recurrence of failures of instrument lines connected to the jacket. water cooling system for the no. IB and no. IC emergency diesel generators.
E.
From July 11, 1992 until June 10, 1995 Sales staff failed to determine the cause, correct, or take action to preclude recurrence of impact noises from the interior of the no. 21 Residual Heat Removal discharge manual isolation valve (21RH10).
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APPEhdLil NOTICE OF VIOLATION Public Service Electric'and Gas Company Docke't Nos:
50-272 50-311 Sales Nuclear Generating Station t
Units 1 and 2 License Nos:
DPR-70 2
DPR-75 i
l During an NRC inspection conducted on.May 7, 1995 - June 23, 1995 violations i
of NRC requirements were identified. In accordance with the ' General Statement of Policy and Procedure for NRC Enforcement Actions,"
2 l
(60 FR 34381; June 30, 1995), the violations are listed below:
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A.
Technical Specification 6.8.1 requires, in part, that written procedures be established, implemented and maintained covering the applicable l
procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 4
2, February 1978. Regulatory Guide 1.33 requires written procedures to j
control safety related maintenance and surveillances. During the j
inspection period, the following examples of failure to adhere to procedures occurred:
1.
Sales maintenance procedure SC.MD-ST.DG-0003, Eighteen Month r
Diesel Engine Inspection Maintenknce, step 5.15.8.G requires that the maintenance technician unlatch the cylinder fuel pump rack i
once the compression pressure is obtained.
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Contrary to the above, at approxi'ately 10:00 p.m. on June 14, m
i 1995, after obtaining the compression pressure for cylinder 4R on the no. IC emergency diesel generator, the technician failed to 4
unlatch the cylinder fuel pump rack. As a result, the licensee operated the diesel with essentially no fuel to the 4R cylinder, I i
of 18 cylinders.
In such condition, a potential existed for an l
adverse affect on the reliability of the IC emergency diesel i
generator.
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2.
Sales surveillance procedure S2.0P-ST.DG-0003, 2C Ofesei Generator Surveillance Test, provides instructions necessary to prove t
i operability of the 2C diesel generator. Step 5.3.45 of S2.0P-i l
ST.DG-0003 requires diesel generator restoration in accordance with Attachment 6. to S2.0P-ST.DG-0003 requires 3
placing the fuel rack linkage to the "open" position.
j Contrary to the above, at 5:55 a.m. on May 16, 1995, the licensee restored the 2C diesel generator to service following surveillance testing and failed to ensure that the fuel rack linkage remained j
i placed in the "open" position.
l i-This is a Severity Level IV violation (Supplement I).
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l B.
10 CFR 50.73 requires, in part, that licensee shall submit a Licensee Event Report within 30 days, for the completion of any plant shutdown required by the plant's Technical Specifications, or any condition that l
1 resulted in the nuclear' power plant being in an unanalyzed condition.
l Contrary to the above, as a result of inoperable switchgear supply fans, i
from December 12, 1994 until May 16, 1995, the licensee operated the
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Salen Unit 1 in an unanalyzed condition. On May 16, 1995, the licensee completed a shutdown of Salem Unit I as required by Technical l
Specification 3.0.3, and the licensee did not report within 30 days the unanalyzed condition, or the shutdown required by Technical 4
i Specification 3.0.3.
This is a Severity Level IV violation (Supplement I).
' Pursuant to the provisions of 10 CFR 2.201, Public Service Electric and Gas Company is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, t
D.C. 20555 with a copy to the Regional Administrator, Region I, and a copy to i~
the NRC Resident Inspector at the facility that is the subject of this Notice, i
l within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a " Reply to a Notice of l
Violation" and should include for each violation:
(1) the reason for the l
violation, or, if contested, the basis for disputing the violation, (2) the l
the corrective steps that have been taken and the results achieved, (3)d (4) the corrective steps that will be taken to avoid further violations, an date when full compliance will be achieved. Your response may reference or include previous docketed correspondence, if the correspondence adequately
[
addresses the required response.
If an adequate reply is not received within i
i the time specified in this Notice, an order or a Demand for Information may be i
issued as to why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause l
is shown, consideration will be given to extending the response time.
Dated in King of Prussia, PA on 14th day of July,1995
.. - -. -. -... -. - -. = - - - -.. _ - - -.
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l U. S. NUCLEAR REGULATORY ComISSION l
REGION I i
Report Nos.
50-272/95-10 l
.50-311/95-10
' License Nos.
DPR-70 DPR-75 I
Licensee:
Public Service Electric and Gas Company l
P.O. Box 236 l
Hancocks Bridge, New Jersey 08038 Facility:
Sales Nuclear Generating Station Dates:
May 7,.1995 - June 23, 1995 Inspectors:
C. S. Marschali, Senior Resident Inspector L
J. G. Schoppy, Resident Inspector l
T. H. Fish, Resident Inspector l
K. S. Kolaczyk, Operations eer L. L. Scholl, Reactor E eer A. E. Finkel enior t
gi eer s p' +
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Approsed:
(
/
John R.
ite, Chief /
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Date React Projects Section 2A Insoection Sumary-l l
This inspection report documents inspections to assure public health and safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security, engineering, technical support, safety assessment and quality verification.
The Executive Summary delineates the inspection findings and conclusions.
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I EXECUTIVE
SUMMARY
Salem Inspection Reports 50-272/95-10; 50-311/95-10 f
May 7, 1995 - June 23, 1995 0PERATIONS (Modulo 71707) Based on preliminary assessment, operators responded effectively to a Sales Unit 2 trip on June 7.
Operators failed to t
fully consider the implications and the risk associated with their actions to i
render an entire service water bay inoperable, instead of just removing control power from the affected component. Operators appropriately assessed i
emergency diesel generator (EDG) operability after operation with essentially no fuel to one of the EDG cylinders.
Ineffective corrective action in response to failures of Residual Heat Removal (RHR) pump minimum recirculation flow valves resulted in operation of Salem Unit 2 from February 9,1995 until June 7,.1995 with both trains of RHR l
In addition, when plant staff recognized the degraded conditions
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on June 6, they perfomed an incomplete and incorrect operability l
determination for the valve associated with the no. 22 RHR pump. The incorrect operability determination, endorsed by the plant management personnel, demonstrated weaknesses in the plant staff's ability to perform operability determinations.
The plant staff did not identify that the December 1994 failure of a supply fan for safety-related switchgear placed Sales Unit I at variance with conditions stated in the Updated Final Safety Analysis Report (UFSAR).
Further, when a second switchgear supply fan failed on May 12, 1995, plant staff did not recognize that they operated the plant in an unanalyzed condition. As a result, the safety related switchgear could have failed under design basis accident conditions. Plant staff did not take the appropriate action to shut the plant down until May 16, 1995.
MAINTEWANCE/ SURVEILLANCE (Modules 61726,62703) Plant staff responded appropriately to Hagan module fuse configuration issues and implemented a Technician inattention to comprehensive Hagan module fuse inspection program.
detail contributed to Maintenance returning IC EDG to service with a cylinder fuel pump inadvertently left out of service. Operations failure to ensure the fuel system was reset, as required by procedure, resulted in reduced emergency diesel generator reliability. Despite extensive troubleshooting and installation of a modification, maintenance staff continued to experience recurrent problems due to a safeguard equipment control auto test fault.
Plant staff did not determine the cause, take adequate corrective action, or
. preclude recurrence of three leak rate test failures for the Salem Unit 1 The plant staff initiated an Incident Report after the outer airlock door.
third failure, in response to questions by the inspector, and discovered that the airlock gasket was defomed, not merely dirty as had been supposed by the l
organization due to inadequate root cause performance.
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ENGINEERING (Module 71707) Based on their identified probable cause, system engineering correctly evaluated the effect of mis-operation of the output breaker on EDG operability. However, they did not rigorously investigate and evaluate other less probable, but more safety consequential causes of the diesel generator output breaker failure.
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Design engineering installed new design high-speed circulating water traveling screen motors without detecting an inherent design problem. Consequently, an operator work-around was devised relative to the manual operation of the screen in lieu of designed automatic. operation. The action challenged the licensee's ability to affect event-free operation.
In addition, design engineering failed to adequately analyze and evaluate the recurring motor failures prior to returning them to automatic operation.
l Engineering thoroughly assessed the consequences of operating IC EDG with essentially no fuel to one cylinder and provided operations a reasonable basis for declaring the emergency diesel generator operable.
Engineering's auxiliary feedwater pump cavitation calculations were found to be technically adequate.
The licensee appropriately identified the cause for installing incorrect internals in the Salem Unit 2 PORVs, and took appropriate corrective action.
PLANT SUPPORT (Module 71707) The Radiation Protection staff took' comprehensive measures to prevent the recurrence of the problems involving entry into high radiation areas.
SELF ASSESSMENT / QUALITY VERIFICATION (Module 71707) In 1992, the licensee identified cyclic impact noises coming from an RHR pump discharge valve.
Although they took some corrective actions in 1993, they did not determine the cause or thoroughly evaluate the potential effects on the operability of the valve and its affect on the RHR system.
In response to inspector concerns on this matter, the licensee performed an acceptable operability determination that provided reasonable assurance of the valve's ability to function and committed to inspect the valve to confirm the conclusion during the current i
outage. Notwithstanding, the inspector determined that, in 1992, the licensee failed to take timely and appropriate corrective action in response to identification of the degraded condition.
Engineering conducted an acceptable root cause determina' tion for recurrent jacket water instrument line leakage that affected one or more of the i
I emergency diesel generators.
In view of several similar failures that occurred since February 1992, the inspector determined that the licensee previously failed to determine root cause and effect lasting corrective action.
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TABLE OF CONTENTS EXECUTIVE
SUMMARY
11 TABLE OF CONTENTS............................
iv 1.0'
SUMMARY
OF OPERATIONS.......................
I i
1 2.0 OPERATIONS............................
2.1 Operator Response to the Salem Unit 2 Trip 1
2 i
2.2 Service Water Operability l
2.3 Operation of IC EDG with a Latched Fuel Pump Rack......
3 2.4 Inoperable Salem Unit 2 Residual Heat Removal (RHR) pumps..
3 2.5 Salem Unit 1 Degraded Switchgear Ventilation System.....
5 7
3.0 MAINTENANCE AND SURVEILLANCE 3.1 MAINTENANCE....*.....................
7 7
l 3.2 Hagan bdule Fuses 3.3 Emergency Diesel Generator (EDG) Maintenance 8
3.4 Safeguard Equipment Control (SEC) Troubleshooting......
9 9
3.5 SURVEILLANCE........................
3.6 Inadequate Corrective Action of Salem Containment Airlock..
10 l
4.0 ENGINEERING............................
10 4.1 Emergency Diesel Generator Output Breaker..........
10 4.2 Circulating Water (CW) Traveling Screen Motors 11 1
4.3 Operation of 1C EDG with a Latched Fuel Pump Rack 12 i
12 4.4 Auxiliary Feed Pump Cavitation i
5.0 PLANT SUPPORT...........................
14 5.1 Radiological Control s....................
14 14 6.0 Self Assessment and Quality Verification 6.1 Historical Problem Identification and Resolution at Salem..
14 16 7.0 REVIEW OF REPORTS AND OPEN ITEMS.................
16 l
7.1 Licensee Event Reports 17 l
8.0 EXIT INTERVIEWS / MEETINGS.....................-
17 i
8.1 Resident Exit Meeting.....................
17 8.2 Specialist Entrance and Exit Meetings............
17 8.3 Salem Management Changes..................
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DETAILS 1.0
SUMMARY
0F OPERATIONS j
Unit I began the period operating at 48% power.to. support modifications to the steam generator feed pumps. Operators began raising power on May 14, 1995.
On May 16, with the unit at 95% power, operators entered Technical l
Specification 3.0.3 and began a plant shutdown, due to inoperable switchgear ventilation supply fans. The operators put the plant.in Mode 5 (Cold i
Shutdown) on May 17, where it remained through the end of the reporting period.
t Unit 2 began the period at 100% power. On May 7, 1995, operators reduced power to 88% due to the loss of moisture separator reheater drain tank level indications. On May 8, with the no. 23B circulating water pump out of service for maintenance, operators reduced power to 78% due to high temperatures in the no. 23A circulating water traveling screen motor. On May 11, operators increased power to 90%.
Maintenance on the no. 21 heater drain pump and l
1evel swings in no. 2B heater drain tank level prevented a further power increase until May 15, when operators returned Unit 2 to 100% power. On May 25, operators reduced power to 88% due to circulating water pump unavailability and anticipated loss of an additional circulating water pump.
On May 30, operators returned Unit 2 to 100% power. On June 3, operators reduced power to 90% due to an extended outage of no. 23B circulating water pump and unreliability of circulating water traveling screr.n motors. On June 4, operators returned Unit 2 to 100% power. On June ~7, Unit 2 operators commenced a shutdown required by Technical Specification 3.0.3 due t.o the inoperability of both trains of residual heat removal (RHR).
During the shutdown, Unit 2 experienced an automatic reactor trip from 10%
i power due to a 500 kV breaker failure and subsequent loss of two of the four I
operating reactor coolant pumps. On June 8, operators placed Unit 2 in mode 5 and maintained it in that condition for the remainder of the inspection period.
2.0 0PERATIONS l
The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors l
performed normal and back-shift inspections, including 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of deep back-shift inspections.
2.1 Operator Response to the Salem Unit 2 Trip Based on preliminary assessment, operators responded effectively to a Salem Unit 2 trip on June 7.
On June 7, during a Salem Unit 2 shut down required by Technical Specification 3.0.3, a reactor trip resulted from spurious protective relay actuation on the l
500 kV ring bus. With the plant at 10 percent power, the protective relaying j
caused loss of the 4160 volt buses supplying power to the nos. 23 and 24 O
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reactor coolant pumps. As a result, the reactor tripped, from. low reactor coolant system flow with reactor power greater than or equal to 10 percent.
The protective relaying also caused loss of power to' other plant equipment i
1.ncluding the control air compressors. The vital bus transfer to its alternate source of offsite power occurred successfully, and the emergency air i
compressors started and restored air pressure. All plant equipment functioned as designed in response to the existing conditions. The inspectors concluded that the operators responded appropriately to the trip. Salem management convened a Significant Event Response Team (SERT) to review operator action i
and plant response to the trip.' The SERT.had not completed its review at the conclusion of the inspection period. The inspectors will' review the completed SERT findings when they become available,' as a matter of routine NRC l
inspection activities.
2.2 Service Water Operability l
j The inspector noted that operators unnecessarily rendered a service water bay inoperable while waiting for post-maintenance testing of a service water pump.
Operators failed to fully consider the increased risk of unnecessarily maintaining a service water bay inoperable, instead of merely removing control power from the affected service water pump breaker.
At 04:51 a.m. on May 26, 1995, operators restored 125 VDC control power to the j
no. 25 service water (SW) pump breaker while waiting for a post-maintenance i
test on the SW pump. At the time, the operators considered the no. 25 SW pump inoperable but availabis. The operators recognized that the restoration of l
control power to the pump would set-up a condition that would cause the no. 2C safeguard equipment control (SEC) system to attempt to start the no. 25 SW pump in the event of a loss of offsite power (LOP); and that if the no. 25 SW j
pump. breaker failed to close, the 2C SEC would attempt to start the 26 SW pump, in accordance with design.
The inspector noted that if the operators had not restored control power to the no. 25 SW pump, 2C SEC would have started the operable no. 26 SW pump, j
directly in response to a LOP. However, as a result of making the no. 25 SW i
pump available with restored control power, an SEC actuation under accident conditions could result in 2C SEC closing the no. 25 SW pump breaker before i
the pump was demonstrated as operable by post-maintenance testing.
In such condition, the pump may not have been able to perform its intended function.
l In such case, the potential existed for not having any pumps in the affected SW bay that would start in response to a LOP.
l When this matter was brought to the attention of the operating personnel, the operators reacted initially by considering the SW bay inoperable'and appropriately entering Technical Specification 3.7.4. while continuing to wait for the performance of a post-maintenance test that was planned for the next j
shift.
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The next morning, the inspector questioned the advisability of the operators
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rendering the entire SW bay inoperable while waiting for a post-maintenance render the entire SW bay inoperable was inappropriate and. hat the decision to test for a single pump.
The Operations Manager concluded t j
unnecessary.
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3 Subsequently, the operations manager took prompt action to ensure the operating shift removed breaker control power for the affected SW pump until maintenance was prepared to perform the post-maintenance test.
The inspector determined that the operators failure to consider 'he t
implications of their approach a contributor to the potential for rendering a portion of SW unable to respond to a LOP; and demonstrated a weakness in understanding and assessing aggregate risk.
2.3 Operation of.1C EDG with a Latched Fuel Pump Rack Operators appropriately considered the emergency diesel generator ('EDG) inoperable after operation with essentially no fuel to one of the EDG cylinders. Later, they appropriately declared the EDG operable after review of information provided by system engineering.
On June 15, during a surveillance of IC EDG, operators identified abnormally low no. 4R cylinder exhaust temperature (165 'F).
Normal cylinder exhaust temperatures for a loaded EDG rahge from 860 to 960 'F.
Subsequently, a maintenance supervisor found the 4R cylinder fuel pump latched, essentially eliminating fuel flow to the 4R cylinder. The supervisor unlatched the fuel pump, returned the' cylinder to service, and operators completed the EDG surveillance run with no apparent degradation in engine performance.
Following the surveillance, the Senior Nuclear. Shift Supervisor (SNSS) declared.the EDG inoperable pending engineering evaluation of running the EDG with no fuel to cylinder 4R. On June 16, engineering provided operations with information indicating the EDG had not experienced damage.
The SNSS declared the EDG operable.
(Sections 3.3 and 4.3 pertain) 2.4 Inoperable Salen Unit 2 Residual Heat Removal (RHR) pumps Ineffective corrective action in response to failures of Residual Heat Removal (RHR) pump minimum recirculation flow valves resulted in operation of Salem Unit 2 from February 9, 1995 until June 7, 1995 with both trains of RHR inoperable.
In addition, when plant staff recognized the degraded conditions on June 6, they performed an incomplete and incorrect operability determination for the valve associated with the no. 22 RHR pump. The incorrect operability determination, endorsed by the plant engineering and operations management, demonstrated fundamental weaknesses in the plant staff's ability to perform operability determinatioris.
On January 26, 1995, as operators decreased flow from no. 22 RHR pump into the reactor vessel, the RHR minimum recirculation flow bypass valve (22HR29) failed to open. Operators noted that, as flow decreased, the valve did not open at 500 gpm, as expected. At 200 gpm flow, operators manually opened the motor operated valve (MOV).
In consultation with the system engineer, operators manually stroked 22RH29 to verify manual operation of the valve.
They initiated a work order stating that the valve failed to open automatically, but considered the valve operable without any basis. 'On February 9,1995, the minimum recirculation flow bypass valve (21HR29) also failed to open automatically in response to a low flow condition. However, m.
t<---e
4 since the operators were able,to stroke the valve manually, they cont.inued to considered the component operable without any other basis. Notwithstanding, a No significant priority work order to investigate and repair was initiated.
Consequently, the actions became part of the was assigned to the work. orders.
licensee's work order backlog even though the work orders described an operability concern.
On June 6,1995, during a review of open safety related work orders, plant staff identified that the work orders for the 21 and 22 RH29 valves identified unresolved degraded conditions potentially affecting RHR pump operability.
(LOCAs)theRHR
. Plant staff noted that for certain loss of coolant accidents pumps would start but would not immediately inject into the reactor coolant Those conditions'would require system (RCS) due to elevated system pressure.
that the 21 and 22 RH29 valves open to assure adequate flow through the RHR pumps to prevent pump failure due to over-hecting or excessive vibration.
With the plant at full power, operators started the nos. 21 and 22 RHR pumps individually with the RH29 valves closed. The 22RH29 opened in response to the low RHR flow; the 21RH29 valve failed to open. The operators, with management concurrence, declared the no. 21 RHR pump inoperable. However, with no other basis than this single functional test, the operators continued to consider the no. 22 RHR pump operable.
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On June 7, 1995, the inspectors questioned the basis for operability of 22RH29.
In response to the inspector's questions, the General Manager confirmed that the plant engineering and operations management considered 22RH29 operable basM solely the functional test and engineering assurance.
When challenged by C.e inspector, neither the general man ~ager nor the engineering or operations staff could provide the basis for this operability determination.
Follow-up revealed that the plant operations and engineering managers assumed that the system engineer, in response to the 22RH29 failure on January 26, 1995, had engineering assurance that permitted him to conclude that the valve was operable at that time.
On June 7, the managers considered the single functional test as sufficient reasonable assurance of operability to arbitrarily established a deadline of 5:00 p.m. to supply further basis for a positive operability determination for However, at 6:27 p.m. on June 7, engineering was unable to provide a 22RH29.
rationale for operability. Subsequently, the operations organization declared the no. 22 RHR pump inoperable, and commenced a Unit 2 shutdown, as required by Technical Specification 3.0.3.
8 In summary, the inspector found that the plant staff did not identify a root cause for either 22RH29 or 21RH29 functional failures in January and February, 1995. Though operability of the RHR system was recognized as an issue, no basis for operability was ever established, and no significant priority was assigned to work efforts to investigate and resolve the matters.
Consequently, the issues remained unresolved until June 7, when the licensee Following finally determined that neither valve could be considered operable.
shutdown of Unit 2, the licensee still unable to demonstrate the proper functioning of the valves, confirming that both trains of the RHR system were inoperable since January / February 1995, during which time the plant was at
_. _ _ _ _ _ _ _. ~ _ _ _ _ _
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5 full power. Unit 2 shutdown on June 7, 1995. Power operation of the Salem Unit 2 for prolonged periods with both trains of RHR inoperable is an apparent j
violation.
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2.5 Sales Unit 1 Degraded Switchgear Ventilation System The plant staff did not identify that the December 1994 failure of a supply 1
fan for safety related switchgear placed Sales Unit I at variance with conditions stated in the Updated Final Safety Analysis Report (UFSAR).
Further, when a second switchgear supply fan failed on May 12,1995, plant l
staff still failed to recognize that they had. operated the plant in an l
The inspector identified that in such condition, the unanalyzed condition.
safety related switchgear could have failed under design basis accident Plant staff did not take the appropriate action to shut the plant conditions.
down until May 16, 1995.
j The UFSAR, section 9.4.6, states'that the switchgear ventilation system is l
designed for continuous operation to maintain safe levels of temperature and cleanliness in the 64' and 84' switchgear rooms as well as the 78' lower
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The electrical penetration and 100' upper electrical penetration rooms.
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UFSAR, section 9.4.6.2.2 further states that the ventilation system consists, in part, of three 50 percent capacity fans to supply fiitered air through j
supply ducts, with two of the three supply fans operating ed t% third as a 4
i' standby.
The switchgear ventilation system supplies cooling to all safety related 4160V, 460V, and 230V switchgear.
11,1994, the no.12 control area switchgear supply fan motor On December breaker tripped on overload due to mechanical failure of the motor bearings.
941211094 to investigate and correct the j
Plant staff wrote work order (WO)
However, the fan remained unrepaired due to the lack of available 4
condition.
parts (the fan motors were obsolete).
1 l
On May 12, 1995, with Salem Unit I at power, the no.13' control area switchgear supply fan motor tripped on overload. Plant staff initiated a Work Order (950512188). On May 14, 1995, at 7:00 p.m., operators completed an i
initial operability determination. The determination concluded that the switchgear remained operable based on the expectation that ambient outside air temperature would remain less than the design assumption of 95'F, that. low initial temperatures in the affected areas would limit the rate of' temperature rise from the onset of an accident permitting timely restoration of at least one fan before reachir.g the design inside air temperature limit of 105'F.
Engineering considerei tre limit of 105'F to be a long term reliability i
concern.
On May 15, 1995,. system engineering provided a memorandum to operations documenting their basis for concluding that the switchgear ventilation remained operable. The memorandum stated that the switchgear ventilation was designed to maintain switchgear ambient air temperature within 65'F - 105'F, but did not state that the UFSAR indicated that the fans were~50 percent capacity, that two were assumed to be running, and the third fan was expected J
The memorandum described the assumption that all j
to be available in standby.
of the Unit 1 exhaust fans were available when, in fact, one of six was out of i
service due to parts problems. System engineering also assumed that a fan could be restored within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, even though some of the components were u
obsolete. For compensatory measures, engineering advised operations to rely on the Unit 2 switchgear exhaust fans, and proposed that the fire doors i
I between Unit I and Unit 2 switchgear rooms be propped 'open to allow Unit 2 to serve as a source of outside air for Unit 1.
The memorandum did not address j
the affect of reduced ventilation on Unit 2, or evaluate the condition relative to fire protection requirements and the existing Appendix R analyses.
To accommodate this proposal, engineering's memorandum suggested that operations disable the CO, automatic function for the 84' switchgear rooms.
The memorandum further stated that the ambient switchgear temperatures were acceptable assuming that the ambient temperature did not exceed 80*F.
In the morning Operations received the memorandum on the evening of May 15.
on May 16, the assistant operations manager noted that the predicted high ambient temperature for the day was expected to exceed 80*F.
Subsequently, i
the operations organization rejected engineering's proposal as unacceptable.
Design engineering began a 10CFR50.59 evaluation to determine if the switchgear could be accepted as meeting the design basis cooling assumptions in its present condition. Later in the afternoon of May 16, design engineering informed operations that they had determined that operation with only one switchgear supply fan constituted an Unreviewe.d Safety Question.
Subsequently, the design engineering organization initiated a effort to develop a Justification for Continued Operation (JCO). The operations organization set a deadline of 9:00 p.m. on May 16, to have the JCO, or to begin to initiate plant shutdown. Shortly after g:00 p.m. on May 16 -
operations initiated a plant shutdown after it became evident that the engineering organization would not be able to prepare a JC0 on schedule.
At 11:10'p.m., design engineering completed the JCO.
It relied on use of Unit 2 switchgear ventilation supply fans, specified daytime temperatures to be less than or equal to 80*F and nighttime temperatures to be less than or The JC0 was based on the proposition that the fire doors equal to 60'F.
between Units 1 and 2 would be blocked open, and that the automatic operation of the CO, fire suppression system would be disengaged. The JC0 concluded j
that Unit I could be safely shut down with loss of the third switchgear ventilation supply fan, provided that the ambient air temperature limitations i
and the blocked open fire door conditions were met. The Salem Operations Review Committee reviewed the JC0 and rejected it at approximately 2:30 a.m.
on May 17.
In summary, the licensee's response to the December 11, 1994 failure of the no.12 switchgear supply fan failed to evaluate switchgear operability or_ the effect on the design basis assumptions (as required by 10CFR50.59). The plant i
staff did not recognize that they did not meet design basis assumptions specified in the UFSAR. As a result, they did not promptly obtain repair or replacement parts for the disabled components.
Further, they did not recognize that the design basis assumption of 95'F ambient air temperature assumed that there were at least two operating supply fans. The engineering analysis to support operability relied on Unit 2 equipment for operability of i
l Unit 1. systems, yet assumed that Unit 2 would be unaffected by a loss of offsite power affecting Unit 1, even though the last two switchyard problems t-e-
7 System that perturbed offsite power affected the vital buse's for both units.
engineering's memorandum to the operations organization failed to specify and an engineering basis for concluding that Unit 2 ventilation would provide adequate motive force for both units. ' Also, the memorandum failed to provide an evaluation of the affect of propping fire doors open and disabling automatic functions of CO, systems.
~ Additionally, when design engineering concluded that operation with a single supply fan constituted an unreviewed safety question, Sales management failed to recognize that they could not support continued plant operation, since design engineering had clearly told them that they were operating the plant i
Although it could have been more timely, outside of the design basis.
operations finally took control, established a deadline, and acted in the absence of engineering support of switchgear operability. Engineering's rationale as documented in their memorandum to operations and in the proposed The SORC appropriately JC0 was dubious and based on invalid assumptions.
i rejected the JCO, however, plant management's judgement to cpasider a JCO, after being informed that the design basis assumptions could not be met, is questionable.
3.0 MAINTENANCE AND SURVEILLANCE i
3.1 MAINTENANCE The inspectors observed portions of the following safety-related maintenance to determine if the licensee conducted the activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.
The inspector observed portions of the following activities:
Work Order (WO) or Design
- Unit, Chance Packnoe (DCP)
Descriotion Salem 1 WO 991027004 RCP Seal Inspection Salem 1&2 WO 950524250 Hagan Module Fuse Inspection Salem 1 WO 95012247 Emergency Diesel Generator no.
IC periodic maintenance j
The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance program.
3.2 Hagan Module Fuses Plant staff responded appropriately to Hagan module fuse configuration issues and implemented a comprehensive Hagan module fuse inspection program.
21, 1995, Unit 1 Instrument and Controls technicians Between May 20 and May identified at least six incorrect fuses installed in Hagan modules. The modules, used in safety-related and non-safety related applications, provide a
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The fuses l
120 VAC output that energizes or de-energizes downstream relays.
J protect the signal input to the Hagan modules, the power supplies, and the output to the relays.
The licensee-identified two fuse misapplications: 1) incorrect voltage ratings (installed 32 V or 125 V ratings vs. specified 250 V), and 2) incorrect fuse current ratings (installed.2A vs. specified 5A; and installed 5A vs.
specified.2A). On May 23, the licensee initiated a program to inspect all Hagan module fuses installed in both Salem units. The inspection placed priority on safety-related systems, but included non-safety related systems.
At the end of the inspection period, Unit I technicians completed inspection of approximately 350 of 113g fuses, with approximately 10 percent of the fuses Unit 2 technicians completed inspection of found to be incorrect.
approximately 440 of 1133 fuses, with approximately 5 percent of the fuses found to be incorrect.
Salem management expected to complete inspections of safety-related systems by the end of July. They had not yet determined the completion date for inspections of the remaining non-safety system modules. NRC inspectors will continue to follow-up on the licensee's resolution of this configuration control problem.
3.3 Emergency Diesel Generator (EDG) Maintenance Technician inattention to detail contributed to Maintenance returning IC EDG to service with a cylinder fuel pump inadvertently left out of service. The inspector also discovared that operations failed to insure the emergency diesel generator fuel rack linkage had been properly repositioned following a surveillance. Although this did not render the diesel inoperable, it reduced reliability of the emergency diesel generator. Both matters represent examples of failure to follow procedures.
As described in Section 2.3, maintenance technicians inadvertently left cylinder 4R fuel pump latched after completing compression. checks on IC EDG. -
The licensee determined that technicians failed to comply with the procedure i
SC.MD-ST.DG-0003, Eighteen Month Diesel Engine Inspection Maintenance, step 5.15.8.G, which requires the technicians to unlatch the fuel pump rack and allow the rack to return to its normal position following compression pressure checks on the cylinder.
The inspectors concluded technician inattention to detail contributed to the fuel pump rack being left latched, and resulted in operators running the EDG without fuel to the cylinder. Failure to correctly implement the maintenance procedure is an example of failure to follow' procecares.
At 5:55 a.m. on May 16, 199'5, operations declared the 2C emergency diesel generator (EDG) operable after completing a surveillance. At approximately 10:00 a.m. on May 16, the inspector discovered the 2C EDG fuel rack linkage was not in the open position. The shift supervisor appropriately restored the fuel rack linkage to the correct position.
In addition, operations ensured that the fuel rack was properly lubricated and functional..
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The licensee determined that an equipment operator's failure to follow procedural requirements for EDG restoration was the root cause. Step 5.3.45 of S2.09-ST.DG-0003, 2C Diesel Generator Surveillance Test, required EDG restoration in accordance with Attachment 6.: Attachment 6 to 52.0P-ST.DG-0003 required positioning of the fuel rack linkage to the open position.
Engineering determined that the incorrectly positioned fuel rack did not affect emergency diesel generator owrability since hydraulic pressure would
- be expected to automatically open tis fuel racks during the starting sequence.
The inspector verified that operations successfully teste'd the automatic
~
e feature on December 4, 1994, during S2.0P-ST.DG-0021, 2C Ofesel Generator #ot Restart Test. The inspector concluded that Attachment 6 to procedure S2.0P-ST.DG-0003 provided a redundant means to assure open fuel racks prior to diesel starts. The licensee's failure to adhere to S2.0P-ST.DG-0003 step 5.3.45 and procedure SC.MD-ST.DG-0003 step 5.15.8.G, as discussed above, constitutes an apparent violation of Technical Specification 6.8.1.
(VIO 50-2721311/95-10-02) 3.4 Safeguard Equipment Control (SEC) Troubleshooting Despite extensive troubleshooting and installation of a modification, the i
maintenance organization has been unsuccessful in preventing recurrence of safeguard equipment control auto test faults.
Previous inspection reports (NRC Inspection Reports 50-272&311/94-31, 50-272&311/94-35, and 50-272&311/95-02) documented recurring problems with Unit 1 SEC power supplies, particularly frequent Automatic Test Insertion (ATI) test faults and spurious alarms. To address the problems, the licensee installed modified SEC power supplies on May 22 and made improvements to reduce' electromagnetic interference. The licensee also planned modifications to the ATI card to reduce sensitivity to noise.
On June 13 and June 20, the 1A SEC again experienced ATI test faults.
Initial analysis indicated that the new power supplies had degraded. At the end of the inspection period, the licensee continued to troubleshoot the power supplies.
3.5 SURVEILLANCE The inspectors performed detailed technical procedure reviews, observed surveillances, and reviewed completed surveillance packages. The inspectors verified that plant staff performed surveillance tests in accordance with approved procedures, Technical Specifications and NRC regulations.
The inspector reviewed the following surveillances:
1 e
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10 MBit Procedure no.
Igit Salem 1 SI.RE-ST.ZZ-0002 Shutdown Margin Calculation Salem 2 S2.0P-ST.RC-0008 Reactor Coolant System Water Inventory Balance Sales 2 S2.IC-FT.RCP-0068 Containment Pressure Protection Channel 2 The inspectors observed that plant staff did the surveillances safely, and that the tests were effective in confirming operability of the associated systems.
3.6 Inadequate Corrective Action of Sales' Containment Airlock Plant staff failed to determine the cause, take adequate corrective action, or' otherwise preclude r'ecurrence of three successive leak rate test failures for the Salem Unit 1 outer airlock door. Although plant staff initiated an Incident Report after the third failure, in response to questions by the inspector the plant staff discovered that tha airlock gasket was deformed as opposed to their initial presumption that dirt in the seal area was the cause of the recurrent test failures.
On March 6,1995, the Salem Unit 1100 foot elevation outer airlock door failed a routine leak rate test.
Plant staff cleaned the gasket with Maselin (oil impregnated) cloth and satisfactorily completed the retest. They concluded that dirt on the gasket had caused excessive leakage during the first test. On May 3,1995, the outer airlock door again' failed a routine surveillance. Plant staff again cleaned the gasket, and satisfactorily On May 8,1995, the door again failed surveillance, and retested the door.
i plant staff again cleaned the gasket with a Maselin cloth, and satisfactorily retested the door.
Though the plant s'taff wrote an Incident Report, they considered the airlock door operable for purposes of containment integrity. ' The inspectors questioned the adequacy of the corrective action, the basis for operability, and the licensee's ability to preclude recurrence.
In response, the licensee thoroughly inspected the gaskets, and found one of the two gaskets sufficiently deformed to cause the excessive leakage. The licensee replaced the damaged gasket and successfully retested the door.
The inspectors concluded that the licensee had not adequately determined the cause of the airlock failure on March 6, May 3, and May 8,1995, with the result that they took inadequate corrective action in each instance.
4.0 ENGINEERING 4.1 Emergency Diesel Generator Output Breaker System engineering performed a thorough operability evaluation based on their identified most probable cause of recurring unsuccessful diesel generator output breaker operation. However, the inspector determined that engineering
I t
11 did not rigorously investigate other potential causes that were factors in, or contributed to, a previous similar diesel generator breaker failure, and other related breaker failure events. The inspector noted that engineering readily dismissed other possible causes with more safety consequence.
On June 2, 1995, the 4KV emergency diesel generator (EDG) output. breaker failed to close on the first attempt while performing S1.0P-ST.DG-0002,1B
' Ofesel Generator Survefilance Test. The licensee experienced similar failures on May 15, 1995, and March 1, 1995, on the IC EDG and the 2A EDG respectively.
In all cases, the breaker closed on the second attempt.
In each case, the 1
licensee attributed the failures to the operator improperly timing the attempt Engineering concluded that the operators must not to close the 4KV breaker.
have satisfied the synchronization permissive required to effect breaker Operations concluded that the breaker failures, that occurred during j
closure.
diesel paralleling, affected only the test portion of the EDG breaker closing circuit.
The inspector determined that plant engineering performed a thorough analysis i
of the affect on operability of a faulty synchronization permissive circuit.
The inspector also noted that on April 12, 1994, engineering determined that increased contact resistance in position switch 52HL caused successive breaker failures on March 29, 1994. The inspector also found that plant engineering did not fully consider potential intermittent. failures of relays and contacts l
in the synchronization permissive circuit and the safeguard equipment control (SEC) EDG starting circuit. Although they concluded that 52HL caused the failure in March 1994, engineering did not consider increased 52HL contact i
In resistance as a cause for the failures in March, May, and June 1995.
addition, engineering did not evaluate other failures of similar 4KV breakers.
The licensee previously attributed four previous failures of 4KV breakers to i
close on the first attempt to dirty, pitted or misaligned permissive switch contacts.
The inspector determined that engineering's recommended' corrective actions were appropriate if the cause of the breaker failing to close was confirmed to be associated with mis-synchronization. The inspector noted, however, that the licensee did not specifically confirm synchronization as the cause, nor investigate other possible causes.
4.2 circulating Water (CW) Traveling Screen Motors Design engineering installed new design high-speed circulating water traveling screen motors that resulted in an operator work-around (i.e., required manual screen operation) and had the potential to challenge event-free operations.
In addition, design angineering failed to adequately analyze and evaluate the recurring motor fat h res prior to returning them to automatic operation.
~
The licensee installed new CW traveling screen motors designed to operate in low speed automatic operation,.with automatic speed increases (2nd, 3rd, and 4th speeds) in response to increasing traveling screen differential pressures.
Shortly after installation, the licensee observed extremely high CW traveling screen motor temperatures while operating the motors in low speed automatic On May 3 and May 6, motor failures occurred due to overheating.
operation.
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On May 8, Unit 2 operators reduced reactor power to 78% due to high temperatures on the no. 23A CW traveling screen motor while the no. 238 CW pump was out of service for maintenance. Based on engineering recommendations, operations placed the screen motors in manual and in 2nd l
speed to reduce the potential for' overheating.
}
Engineering determined that poor workmanship and insufficient end-turn winding insulation caused the motor failures. Engineering had two of the motors i
rewound and properly insulated. Prior to making this modification to all new motors, however, engineering recommended that operations place all motors back j
in low speed automatic operation. Engineering based the recommendation on a l
l grease and bearing evaluation and on motor design specifications. Despite the failures experienced, engineering determined that the motors should have performed as designed. On May 17, operators placed all the traveling screen j
motors in low speed automatic operation. On May 25, operators reduced power l
to 88% due to an overheating failure of no. 23A traveling screen motor and i
anticipated loss of additional motors due to overheat. Subsequently, operations returned the motors to 2nd speed manual operation.
4.3 Operation of IC EDG with a Latched Fuel Pump Rack Engineering thoroughly assessed the consequences of operating IC EDG with essentially no fuel to one cylinder.and provided operat' ions a reasonable basis for declaring the emergency diesel generator operable, i
System Engineering assessed the impact of running the EDG with the fuel pump latched (described in Section 2.3 and 3.4). Engineers evaluated torsional resonance resulting from one cylinder not firing, and thennal loading on the l
17 operating' cylinders and the non-operating cylinder. They discussed these issues with the EDG vendor, a consulting firm, and three other utilities.
They also reviewed event reports and industry data to identify other examples of diesel engines running with a cylinder not firing. Based on the collective experience of the engine manufacturer, consultants, other utilities, and broad l
l industry experience, engineering concluded the IC emergency diesel generator suffered no damage from running with a fuel pump rack latched.
4 4.4 Auxiliary Feed Pump Cavitation The inspector reviewed auxiliary feedwater pump cavitation calculations and found them to be technically adequate.
The licensing basis of the Salem auxiliary feedwater (AFW) system is described J
in section 10.4.7.2.1 of the Updated Final Safety Analysis Report (UFSAR).
The AFW system serves as a backup for supplying feedwater to the secondary l
side of the steam generators at times when the main feedwater system is not i
available, thereby maintaining the heat removal capabilities of the steam i
generators.
Each unit is equipped with one turbine-driven and two motor-j driven auxiliary feed pumps.' Steam for the turbine driven pump is taken from The i
two of the four steam lines upstream of the steam generator stop valves.
j The motor-driven pumps receive power from the 4160 volt Class IE vital buses.
i system.provides an alternate to the main feedwater system during startup, hot i
In the latter standby, and also functions as an engineered safeguards system.
13 case, the AFW system is directly relied upon to prevent core damage and reactor coolant system over pressurization, in the event of transients, such as loss of feedwater or a secondary system pfpe rupture.
It also provides a i
means for plant cooldown following any plant transient.
The inspector reviewed fou* auxiliary feedwater cavitation calculations. The i
>urpose of these calculations was to predict AFW configurations that were
>ounded with respect to pump cavitation.
Calculation D01.6-835,." Limiting Condition for AFW Pump Cavitation Using l
Best Estimate Calculations," dated' July 27, 1992; l
)
Calculation D01.6-836, "Best-estimate AFW Pump Cavitation During the First Ten Minutes of a Split Steam Line Break," dated August 8, 1992; Calculation S-C-F400-MDC-0225-1, "AFW Flow Rate t "fer Main Steam Line Break and a Single Active Failure," dated July 10, 1992; and Calculation IEC-3220, "AFil and AF21 Modification (Trim Replacement),
Package'no. 1," dated December 15, 1993.
PSE&G 10CFR50.59 Review and Safety Evaluation no. S-0-AF-MSE-0812 dated 17, 1992, evaluated the consequences of potential auxiliary September feedwater pump cavitation on Salem's licensing basis by reevaluating the UFSAR Chapter 15 analyses of steam line break (SLB) and feedwater line break (FWLB) accidents. The reevaluation (above calculations) conservatively assumed the, turbine driven auxiliary feed pump was not available for mitigation of the SLB or FWLB events. Percent cavitation was defined as the percentage reduction in net positive suction head (NPSH) below that required by the pump during the The purpose of the safety evaluation was to document that design basis event.
the postulated worst case of 20% cavitation of one or two auxiliary feed pumps for 10 minutes or less under postulated SLB and FWLB accident events did not involve an unreviewed safety question.
i The inspectors noted that Byron Jackson Pump Division letter dated August 7, 1992, documented a research test project that was completed by Byron Jackson in 1967. The purpose of this test (Byron Jackson Test Curve and Data no. T-28925-1, dated 21 June 1967) was to determine if extreme cavitation conditions over a period of tir.0 would cause pump seizure, bearing failure, and loss of The test pump, which was the sam 9 model (though a different pump performance.
size) as Salem's auxiliary feed pump eight-stage DV2 model pump, was selected to undergo a test program. The test pump was run for a period of one hour with 20% cavitation (i.e., available NPSH was equal to 80 percent of what was required) and there was no appreciable pump noise increase nor bearing temperature rise. Further, the tested pump resumed its normal performance after one hour of cavitation.
PSE&G has analyzed 23 postulated cases of main steam line and feedwater line break accident scenarios. The worst case, a postulated FWLB, has concluded that one motor-driven auxiliary feed pump and is expected to cavitate 3%
(available NPSH of 97%) at two minutes into the accident, and 19% at the end of 10 minutes when the faulted loop was isolated by the operator.
d 14 Simultaneously, the turbine driven auxiliary feed pump is dxpected to cavitate in the range of 4-16% from six minutes into the accident until the faulted loop is isolated.
In above scenario, both pumps were postulated to cavitate less than 20% for less than ten minutes. Based on the Byron Jackson research
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pum) test, PSE&G concluded that the Salem auxiliary' feed pump performance, witi less than 20% cavitation for less than 10 minutes, would not affect pump perfomance. Therefore, PSE&G concluded that these conditions were acceptable and do not involve an unreviewed safety question.
5.0 PLANT SUPPORT 5.1 Radiological Controls In response to previously identified problems with control of entry into high radiation areas, the radiation protection (RP) staff made significant changes
, to the process for entry into the radiologically controlled area (RCA). The changes included positive measures to insure that RP technicians inform each person entering the RCA of the radiologically conditions in the specific areas entered by the workers. The RP staff also revised the Radiation Work Permits to require that each radiation worker read and sign a summary of the problems with control of entry into the high. radiation areas. The inspectors concluded that the RP staff took comprehensive measures to prevent recurrence of the problems with entry into high radiation areas.
6.0 Self Assessment and Quality Verification 6.1 Historical Problem Identification and Resolution at Salem A.
In 1992, the licensee identified cyclic impact noises coming from a Residual Heat Removal (RHR) pump discharge valve. Although they took some corrective actions in 1993, they did not determine the cause or thoroughly evaluate the potential effects on the operability of the valve and the RHR system until the problem resurfaced in 1995. The inspector identified a loss of RHR capability scenario that the licensee had not considered.
In response, the licensee perfomed an acceptable operability determination and committed to thoroughly inspect the suspect valves during the current outage. The inspector also determined that Salem plant staff performed an acceptahls operability determination in response to a IB Emergency Diesel Generator (EDG) jacket water leak on June 1, 1995. However, the licensee did not adequately address previous similar failures that had occurred since February 1992.
Although Sales staff recently took appropriate corrective action,' these two recurring problems demonstrate that previous' inadequacies in root-cause and corrective action determination continue to impact current plant operations.
On July 11, 1992, Engineering identified a loud clanking noise internal to 21RH10, the no. 21 residual heat removal pump discharge gate valve.
On April 16, 1993, maintenance performed an internal valve inspection for wear and deterioration. Maintenance found two deep wear marks in the downstream seat of the double-disk wedge gate valve.
Engineering determined that the defects did not interfere with the valve function
t 15 and were not within the " blue-dye" region that defines the seating surface. Maintenance polished the valve seat and operations considered the valve operable. The licensee did not perform an operability determination, root cause evaluation, or thorough potential failure analysis.
On June 10, 1995, operations identified that 21RH10 made a loud noise internally and that plant staff identified the same problem in 1992.
Operations, based on discussion with system engineering, determined that t1e valve should be opened and inspected, but that the operability of the no. 21 RHR pump was not effected. Engineering worked to document the basis for the operability determination. On June 11, the inspector questioned the licensee's initial operability determination and postulated a potential failure modes of the 21RH10 valve, i.e.,
detachment of the valve disk from the stem such that it impedes or prevents RHR flow through the valve. The inspector identified that the lizensee's plan to take the no. 22 RHR pump out of service to work on l
t'ne 22RH29 valve, coupled with the postulated failure of 21Ril10, could l
yesult in a complete loss of all RHR capability.
On June 16, 1995, system engineering and maintenance met with inspectors I
to disco s RH10 operability. They concluded that the RH10 valves for both trains of RHR remained operable based on a search of industry and Sales data bases. The search revealed with no identified failures where the disk actually separated from the stem. In addition, plant staff concluded that a fatigue induced separation of the disk from the stem would require multiple failures at the most susceptible failure points, i
Plant management stated that they planned to open and inspect 21RH10 to evaluate the effect of the banging on the valve internals when plant conditions permitted taking the no. 21 RHR system out of service. The inspectors concluded that the plant staff was able to demonstrate a reasonable basis for RH10 operability in this case, based on equipment history and engineering judgement of the reliability of the valve design.
The inspectors noted, however, that plant staff did not adequately determine the root cause of the clanging and evaluate the effect on operability in 1992 when first identified.
B.
On June 1,1995, during a surveillance run'of no. IB EDG, the licensee identified jacket water leaking from a pressure switch instrument pipe nipple. The workers secured the EDG to stop the leak and began troubleshooting.
Laboratory analysis revealed that the nipple cracked completely through the threaded area due to fatigue caused by vibration. The licensee confimed this conclusion by performing resonance testing on EDG 18.
The testing found that the pressure switch instrument piping was susceptible to resonance frequency of 90 cycles per second, a harmonic j
of EDS steady state speed of 900 rpm (or 15 cycles per second).- Similar
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resonance testing on all remaining EDGs, including Unit 2, found EDG IC l
also susceptible to resonance frequency vibration.
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16 As an interim measure to eliminate the resonance, engineering proposed
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to change the length of the instrument tubing. Engineering recommended 4
reorienting the tubing and moving the mounting brackets as permanent i
solutions. At the conclusion of the inspection period, the licensee had implemented the interim measure on EDG IC.
The inspector noted that during troubleshooting efforts the licensee i
identified two previous pipe nipple failures that resulted in jacket l
water leaks. The IC EDG experienced a jacket water leak in February i
1992 and the IB EDG 1eaked in December 1993: To address those failures j
the licensee replaced the nipple on IC, and re-threaded and reinstalled the nipple on the IB IDG. Tne inspector concluded the corrective i
actions for the 1992 tipplc failure, since they were not based on any i
established root cause, did not prevent recurrence of the degraded condition for the IC or other EDGs.
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l The inspectors identified that the licensee's failure to thoroughly evaluate i
and resolve the anomalous condition of the RH10 valve and to establish a root cause of the EDG jacket water leakage problems when these conditions were first apparent continues to result in potential challenges to safe plant operation. Accordingly, failure to take adequate corrective actions regarding i
the pipe nipple failures and resolution of the RH10 anomalous conditions are considered as apparent violation of 10 CFR 50, Appendix B, Criterion XVI, i
Corrective Action.
t 7.0 REVIEW 0F REPORTS AND OPEN ITEMS L
7.1 Licensee Event Reports The ' inspectors reviewed the following Licensee Event Report (LER) to confirm that the licensee took the corrective actions stated in the report, responded to the event adequately, and met regulatory requirements and commitments:
Salem Unit 1 Plumber Event Date Description LER 95-007 May 5, 1995 Emergency Diesel Generators IA, IB, and IC Paralleled Concurrently to Electrical Grid (Assessed in NRC Inspection Report 50-272&311/95-07)
The inspectors determined that the LER listed above did not identify any violations beyond those previously identified in NRC Inspection Reports, and considered the LERs closed.
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Section 6.2 of this report provides details of inoperable Salem Unit 1 switchgear supply fans from December 12, 1994 until May 16, 1995. As a result l
of the inoperable fans, Salem Unit 1 operated in an unanalyzed condition i
during that period. On May 16, 1995, operators completed a shutdown of Salem-Unit I required by ' Technical Specification 3.0.3.
However, the inspectors i
confir:.ed that the licensee did not report the unanalyzed condition or the i
shutdown required by Technical Specification 3.0.3 within 30 days as required j
by 10 CFR 50.73. - This is a violation (VI0 50-272&311/95-10-03) l l
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4.0 EXIT INTERVIEWS / MEETINGS l
1 8.1.
Resident Exit Meeting l
The inspectors met with Mr. J. Summers and other PSE&G personnel periodically r
i and at the end of the inspection report period to summarize the scope and findings of their inspection activities.
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Based on NRC Region I. review and discussions with PSE&G, the inspectors l
determined that this report does not contain information subject to 10 CFR 2 restrictions.
i 8.2 Specialist Entrance and Exit Meetings
{
Inspection Reporting Date(s)
Sub.iect Report No.
Insoector 5/11-12/95 EDSFI Followup
' 50-272 and 311/95-11 Cheung l
Inspection 8.3 Salem Management Changes PSE&G appointed Elbert (Bert) Simpson as senior vice president-nuclear engineering, effective June 30, 1995. Mr. Simpson will replace Stanley i
LaBruna. Mr. Simpson has served for the past two years as vice president-i nuclear support for Arizona Public Service Company. Also, the Nuclear Licensing and Regulation Department was re-organized under the Quality Assurance and Nuclear Safety Review organization.
4 1
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I
p te be, UNITED STATES
[
g NUCLEAR RECULATCRY COMMISSION ATTACHMENT 6 O
'j REGION 1 l
475 ALLENDALE ROAD
! --Q
- e,. e */c KING OF PRUSSIA, PENNSYLVANIA 19406-1415 Q
June 9, 1995 CAL No. 1-95-009 I
l Mr. Leon Eliason i
President-Nuclear Business Unit and l
Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey l
SUBJECT:
CONFIRMATORY ACTION LETTER
Dear Mr. Eliason:
On May 16, 1995, you shutdown Salem Unit 1, as required by Technical Specifications, due to Nos.12 and 13 switchgear room supply fans being inoperable. On June 7,1995, you comenced shutdown of Salem Unit 2, as required by Technical Specifications, due to both trains of the RHR system being inoperable. During the shutdown process, Unit 2 tripped due to apparent l
problems experienced with electrical breakers associated with the 500 KV i
switchyard, resulting in loss of power to some vital and non-vital buses. The J
unit was stabilized and shutdown, but the operators experienced several challenges that required their intervention due to the unexpected loss of power and long-standing equipment performance issues.
In both cases, your staff's performance relative to timely recognition and resolution of the x
specific safety and technical concerns., prior to your decision to shutdown the units, was deficient.
In a telephone discussion on June 9,1995, you committed to maintain the Salem units in shutdown condition pending the completion of the following:
1.
The performance of a Significant Event Response Team (SERT) review of the circumstances leading to, and causing the Salem Unit 2 reactor trip, and communication of your findings to the NRC.
l 2.
The performance of a special team review of long-standing equipment reliability and operabilit, !ssues, including corrective maintenance and operator work-arounds; t8a < 'fectiveness and quality of the management oversight and review of G.se matters; and communication of your findings to the NRC.
3.
A meeting at the Salem facility with NRC representatives to describe, discuss and gain NRC agreement on the scope and comprehensiveness of your plan for the performance of a operational readiness review in support of startup of each Salem unit, including the description of the issues that are required to be resolved prior to restart.
4.
The performance of an operational readiness review at each Salem unit.
l 0 1
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Mr. Leon Eliason 2
Meetings with NRC representatives to describe the outcome and 5.
conclusions of the operational readiness review for each Sales unit; and to gain my agreement that each Salen unit is sufficiently prepared to restart..
Pursuant to Section 182 of the Atomic Energy Act, 42 U.S.C. 2232, you are required to:
f 1)
Notify me immediately if your understanding differs from that set forth above; j
2)
Notify.me in writing when you have completed the actions addressed in this Confirmatory Action Letter.
Issuance of this Confirmatory Action Letter does not preclude issuance of an l
order femalizing the above commitments or requiring other actions on the part of the licensee; nor does it preclude the NRC from taking enforcement action l
for violations of NRC requirements that may have prompted the issuance of this i
letter.
In addition, failure to take the actions addressed in this Confimatory Action Letter may result in enforcement action.
The responses directed by this letter are not subject to the clearance.
procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No.96-511.
In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of
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'this letter, and your subsequent response (s) will be placed in the NRC Public
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To the extent possible, your response (s) should not Document Room (POR).
include any personal privacy, proprietary, or safeguards information so that it.can be placed in the PDR without redaction. However, if you find it necessary to include such infomation, you should clearly indicate the specific information that you desire not to be placed in the PDR, and provide the legal basis to support your request for withholding the information from the public.
Sincerely, 1
Thomas T. Martin Regional Administrator
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Docket No. 50-272; 50-311 License No. DPR-70; DPR-75 O
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