ML20203C092
| ML20203C092 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 04/23/1997 |
| From: | Satorius M NRC OFFICE OF ENFORCEMENT (OE) |
| To: | Collins S, Goldberg J, Merschoff E NRC (Affiliation Not Assigned), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV), NRC OFFICE OF THE GENERAL COUNSEL (OGC) |
| Shared Package | |
| ML20203B905 | List: |
| References | |
| FOIA-99-76 EA-97-184, NUDOCS 9902110193 | |
| Download: ML20203C092 (17) | |
Text
April 23, 1997 MEMORANDUM TO:
Ellis W. Merschoff, Regional Admynistrator Region IV Samuel J. Collins, Director Office of Nuclear Reactor Regulation Jack R. Goldberg, Deputy Assistant General Counsel for Enforcement Office of the General Counsel FROM:
Mark A. Satorius, Deputy Director Office of Enforcement
SUBJECT:
01 REPORT 4-97-003; RE: RIVER BEND STATION (RBS) -
FALSIFICATION OF FIRE WATCH LOGS The above referenced 01 report was initiated to determine if an Entergy Operations, Inc, River Bend Station contract fire watch had deliberately failed to conduct fire watch roune and had then falsified fire watch logs to indicate that he had performed the rounds.
The licensee had identified on January 6, 1997, that it had suspected the individual in question had been falsifying fire watch logs.
A licensee internal investigation substantiated the assertion and on March 12, 1997, a RIV physical security inspector made a preliminary determination that the licensee's internal review was thorough and complete.
The inspector further determined that as a result of the fire watch log falsifications, the licensee had violated 10 CFR 50.48, Appendix R requirements.
Based on the 01 review of documentation submitted by the licensee, 01 concluded that the allegation that fire watch rounds had not been performed and records were falsified, was substantiated.
Accordingly, it appears that enforcement action is warranted.
We understand that NRR, RIV, and 0GC will be prepared to discuss this issue during the regularly scheduled RIV enforcement panel on May 8,1997, and we propose to develop an enforcement strategy at that time.
Terry Reis of my staff has been assigned responsibility for this case and for tracking purposes it has been assigned EA 97-184.
Please call him at (817) 860-8185 regarding any questions.
cc.
E. Jordan, DEDR R. Zimmerman, NRR G. Caputo, 01 G. Sanborn, RIV M. Rafky, OGC D.'Wigginton, NRR DISTRIBUTION JLieberman, OE MSatorius, OE TReis, OE Day file 01 file
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i Limerick Generating Station 1
Predecisional Enforcement Conference
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June 2,1997
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AGENDA Introduction W. MacFarland Chemistry Event R. Boyce Fire Protection Everit D. LeQuia Site-Wide Actions R. Boyce Limerick Culture W. MacFarland Enforcement Policy W. MacFarland Considerations Conclusions G. Rainey
~n' Fire Protection Event Personnel teamwork interviews conducted Potential surveillance discrepancy identified-l 1
Fire Protection line management review conducted Discrep.ancy substantiated l
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e Immediate Actions i
XQA/ Corporate Security investigation initiated Individual's unescorted access suspended r
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v Investigation Results NQA/ Corporate Security investigation
- One individual involved
- Six surveillances falsified
- Acted on own accord-Investigation expanded within FP Group
- Two other discrepancies identified
- Two other individuals involved
- Concluded no intent to falsify records
Immediate Follow-up Actions Individual's employment suspended i
Applicable surveillances re-performed.
No plant safety consequences confirmed 1
Expectations reinforced within FP Group i
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Expectations reinforced within Site Support Division Letter from Vice President issued to all site personnel i
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Site-Wide Actions Site-wide independent assessment I
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Limerick Culture t
t History of openness Various methods of self-identification PECO Energy Advantage Openness culture continues s
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Plant Safety Significance Identification Credit Corrective Action Credit l
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1 Plant Safety Significance Affected RECW sample not contaminated All affected FP equipment operable No plant safety consequences I
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Corrective Action Credit Prompt - immediate actions Corrective actions appropriately comprehensive to prevent recurrence i
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. S UNITED STATES y
p, NUCLEAR REGULATORY COMMISSION 5.?
- j REGtON IV 0,
611 RYAN PLAZA DR!VE. SUITE 400
%..... [g ARUNGToN TEXAS 76011-8064 June 26, 1997 EA 97-184 John R.' McGaha, Vice President - Operations River Bend Station Entergy Operations, Inc.
P.O. Box 220 St. Francisville, Louisiana 70775
SUBJECT:
NRC INSPECTION REPORT 50-458/97-08 AND NOTICE OF VIOLATION
Dear Mr. McGaha:
An NRC inspection was conducted April 27 through June 7,1997, at your River Bend Station reactor facility. The enclosed report presents the scope and results of that inspection.
During the 6-week period covered by this inspection period, your conduct of activities at the River Bend Station facility was generally characterized by safety-conscious operations, sound
. engineering and maintenance practices, and good radiation protection support. We are concerned, however, about two violations of NRC requirements that were identified.
The first violation resulted from operators failing to declare a Notification of Unusual Event when they entered the Technical Specification Limiting Condition for Operation for reactor coolant system pressure boundary leakage, as required by the River Bend Emergency Plan. The second violation, which was identified by your staff, occurred because 105 hourly fire watch tours required by the fire protection program were not performed by a single individual over a 2-month period.
l We are concerned that your staff did not have an effective process in place to ensure that l
required fire watch tours were performed as scheduled; however, we note that your staff did l
recognize 4 months later that an ineffective process existed.
l Th'ese violations are cited in the enclosed Notice of Violation (Notice) and the circumstances j
l surrounding the violations are described in detail in the enclosed report. Please note that you are l
l required to respond to this letter and should follow the instructions specified in the enclosed
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Notice when preparing your response. The NRC will use your response, in part, to determine t whether further enforcement action is necessary to ensure compliance with regulatory j
. requirements.
-In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter, its enclosure (s), arid your esponse will be placed in the NRC Public Document Room (PDR). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction.
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Shoud you have any questions concerning this inspection, we will be pleased to discuss them
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with you.'
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Sincerely, Ken E. Brockman for -
Thomas _P. Gwynn, Director Division of Reactor Projects Docket No.: 50-458 License No.: NPF-47
- EA 97-184
Enclosures:
- 1. Notice of Violation -
- 2. NRC Inspection Report 502458/97-008
' cc w/ enclosures:
Executive Vice President and Chief Operating Officer -
Entergy Operations, Inc.
P.O. Box 31995 Jackson, Mississippi-39286-1995 Vice President Operations Support Entergy Operations, Inc.
P.O. Box 31995 -
Jackson, Mississippi 39286-1995 General Manager -
Plant Operations River Bend Station Entergy Operations, Inc.
P.O. Box 220 St. Francisville, Louis'iana '70775 (Director - Nuclear Safety River Bend Station Entergy Operations, Inc.
P.O. Box 220
.St. Francisville, Louisiana 70775 Wise, Carter, Child & Caraway P.O. Box 651 i
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Entergy Operations, Inc. '
Jackson, Mississippi 39205 Mark J. Wetterhahn, Esq.
Winston & Strawn 1401 L Street, N.W.
Washington, D.C. 20005-3502 Manager - Licensing River Bend Station Entergy Operations, Inc.
P.O. Box 220 St. Francisville, Louisiana 70775 The Honorable Richard P. leycub Attorney General P.O. Box 94095 Baton Rouge, Louisiana 70804-9095 H. Anne Plettinger 3456 Villa Rose Drive Baton Rouge, Louisiana 70806 President of West Feliciana Police Jury P.O. Box 1921 St. Francisville, Louisiana 70775 Larry G. Johnson, Director Systems Engineering Cajun Electric Power Coop. Inc.
10719 Airline Highway P.O. Box 15540 Baton Rouge, Louisiana 70895 William H. Spell, Administrator Louisiana Radiation Protection Division P.O. Box 82135 Baton Rouge, Louisiana 70884-2135 1
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- Entergy Operations,'Inc. !
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E-Mail report to T. Boyce (THB)
-l E-Mail report to NRR Event Tracking Systern (IPAS)
- E-Mail report to Document Control Desk (DOCDESK)
E-Mail report to Richard Correia (RPC)
E-Mail report to Frank Talbot (FXT) bic to DCD (IE01) bec distrib by RIV:-
Regional Administrator Senior Resident inspector (Grand Gulf)
DRP Director
- DRS-PSB
- Branch Chief (DRP/D).
MIS System.
Project Engineer (DRP/D) -
. RIV File
< Branch Chief (DRP/TSS)
Resident inspector
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. DOCUMENT NAME: R:\\_RB\\RB708RP.WFS To Nwe copy. ', document, indicate in box: "C" = Copy without enclosures "E" = Copy with enclosures 'N' = No copy SRI-C:DRP/PS C:DRP/D D:DRP WFSmith -
BMurray PHHar, ell TPGwynn -
6/20/97 6/23/97 6/20/97 6/26e97 OFFICIAL RECORD COPY l_
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ENCLOSURE 1 NOTICE OF VIOLATION Entergy Operations, Inc.
Docket No.:
50-458 River Bend Station License No.: NPF-47 EA 97-184 During an NRC inspection conducted on April 27 through June 7,1997, violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed below:
A.
10 CFR 50.54(q) states, in part, that a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans that meet the requirements of 10 CFR Part 50, Appendix E.10 CFR Part 50, Appendix E, requires detailed procedures for implementing the emergency plan.
Emergency implementing Procedure EIP-2-001, " Classification of Emergencies," Revision 8, implements the requirements of 10 CFR 50.54(q) and 10 CFR Part 50, Appendix E.
Emergency Action Level 3 of Procedure EIP-2-001 required the licensee to declare a Notification of Unusual Event upon entry into Technical Specification Limiting Condition for Operation 3.4.5 because of reactor pressure boundary leakage.
Contrary to the above, on May 6,1997, the licensee failed to follow Procedure ElP-2-001 in that the licensee entered Technical Specification Limiting Condition for Operation 3.4.5 upon determination that pressure boundary leakage existed, but did not declare a Notification of Unusual Event until prompted by the inspectors on May 7,1997.
This is a Severity Level IV violation (Supplement Vill) (50-458/97008-05).
B.
Technical Specification 5.4.1.d states, in part, that written procedures shall be implemented covering fire protection program implementation.
Fire Protection Procedure FPP-0070, " Duties of Fire Watch," Revision 8, required, in part,
- the fire watch person to visually inspect each area listed on the patrol fire watch route log.-
Contrary to the above, between November 1,1996, and January 6,1997, one individual failed to complete 105 of his 305 assigned hourly fire watch tours to v;sually inspect each area listed on the patrol fire watch route log.
This is a Severity Level IV violation (Supplement 1)(50-458/97008-06).
Pursuant to the provisions of 10 CFR 2.201, Entergy Operations, Inc. is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011, 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 0dM-
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contested, the basis for disputing the violation, (2) the corrective steps that have been taken and I
the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the 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.
Because your response will be placed in the NRC Public Document Room (PDR), to the extent possible, it should not 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 information, 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.
Dated at Arlington, Texas this 26th day of June 1997 1
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l ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket No.:
50-458 1.
License No.:
NPF-47 Report No.:
50-458/97-008-Licensee:
Entergy Operations, Inc.
Facility:
River Bend Station 1
' Location:
5485 U.S. Highway 61
.i St. Francisville, Louisiana 70775 Dates:
April 27 through June 7,1997 Inspectors:
W. F. Smith, Senior Resident Inspector
, D. L. Proulx, Resident inspector
- Approved By:
P. H. Harrell, Chief, Project Branch D Division of Reactor Projects
Attachment:
- Supplemental'Information i
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l EXECUTIVE
SUMMARY
River Bend Station NRC Inspection Report 50-458/97-008 This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a G-week period of resident inspection.
Ooerations In general, the conduct of plant operators was professional and reflected a focus on safety. Decisions made in support of maintenance were usually conservative (Section O1.1).
A noncited violation (NCV) was identified for failing to enter the Technical Specification (TS) Limiting Condition for Operation (LCO) when two containment isolation valves were rendered inoperable (Section O1.2).
The operators responded well to the May 6 loss of two reactor feedwater pumps by manually scramming the reactor in anticipation of an automatic scram on low water level in the reactor vessel. The licensee's staff also demonstrated good teamwork as they dealt with the complications caused by the loss of power (Section 01.3).
The Equipment Out of Service (EOOS) monitor in the control room was not adequately maintained current with the Safety and Engineering Analysis (SEA) computer, resulting in differences in calculated risk (Section O2.3).
Contingencies planned, but not used, for operating with reactor recirculation system flow control Valve (FCV) B locked open conflicted with the TS (Section 03.1).
Maintenance The workers who inadvertently cut and shorted a control cable while breaching a penetration in the turbine building facilitated a timely determination of the cause of the I
scram on May 6 by promptly informing the control room when the lights went out (Section 01.3).
l Maintenance performed on a low pressure core spray system output breaker was well j
conducted (Section M1.1).
The licensee's approach to the weld failure on the FCV B vent valve was appropriate to the circumstances (Section M1.2).
Plant personnel demonstrated excellent performance in the planning, troubleshooting, and repair of FCV B. Exposures were kept c.3 low as reasonably achievable (ALARA) through the use of mockups and frequent briefings (Section M1.3).
Surveillance tests observed were wen conducted (Section M1.4).
L I-. An NCV was identified for three examples of failing to properly establish clearances for maintenance work (Section M4.1).
Enaineerina The Significant Event Response Team (SERT) issued a thorough and comprehensive root cause analysis report after investigating the scram of May 6,1997. The root causes and corrective actions were appropriate to the circumstances (Section 01.3).
j An NCV was identified for failing to properly configure the standby gas treatment system (SGTS) with the recirculation dampers open during surveillance testing (Section E1.1).
Plant Sucoort Housekeeping was excellent throughout the plant, with minor exceptions noted during a 1
drywell walkdown inspection (Sections O1.1 and O2.1).
A violation was identified for failing to declare a Notification of Unusual Event (NOUE)
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when operators determined that reactor coolant system pressure boundary leakage existed (Section P4.1).
I' The licensee's fire protection program was flawed in the area of hourly fire watch implementation in that no process was in place to ensure that the hou.rly tours were l
completed as scheduled. A violation resulted from a failure to properly implement 105 hourly firewatch tours. Also, an NCV resulted from a failure to properly implement one hourly firewatch tour for a different reason (Section F1.1).
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Report Details Summarv of Plant Status The plant operated at essentially 100 percent power from the beginning of this inspection period until May 6,1997, whcn an operator manually scrammed the reactor upon Icss of power to two of the three reactor feedwater pumps. This forced the plant into an outage where the licensee could repair a stuck reactor recirculation FCV and resolve the slowly increasing drywell unidentified leak rate. With repairs completed, the outage ended on May 17, as the main generator was synchronized to the power grid. Operators increased power to 100 percent power on May 20, where the plant continued to operate sotil the end of this inspection period.
- 1. Operations 01 Conduct of Operations 01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant operations, including control room observations, attendance at plan-of-the-day meetings, and plant tours. In general, the conduct of plant operators was professional and reflected a focus on safety. Decisions made in support of maintenance were usually conservative based on the inspectors' independent reviews of TS LCOs entered and exited, with exception of the problem discussed in Section 01.2 below. During plant tours, the inspectors found that housekeeping continued to be excellent.
01.2 Failure to Enter Containment isolation Valve LCO a.
inspection Scope (71707)
The inspectors reviewed the licensee's actions in response to Condition Report (CR) 97-0762, where the operators identified a failure to enter the appropriate TS LCO when two primary containment isolation motor-operated valves (MOV) were deenergized in the open position for routine maintenance on the actuators.
b.
Observations and Findinas At 4:15 a.m. on May 21,1997, a clearance order was implemented to perform preventive maintenance activities on the actuators of primary containment isolation Valves E12-MOVF004A, the low pressure coolant injection (LPCI) Pump A suppression pool suction, and E12-MOVF064A, the LPCI Pump A miniflow bypass. This action rendered LPCI Train A inoperable. The operators entered TS LCO 3.5.1, which requires restoration of LPCI Train A in 7 days or shut down of the plant. The operators also appropriately entered TS LCO 3.6.2.3, which requires Train A suppression pool cooling to be restored in 7 days or shut down of the plant.
At 8:58 a.m. on May 21, the operators recognized that the two primary containment isolation valves mentimed above were deenorgized in the open position, thereby disabling the safety function cr manual containment isolaten. TS LCO 3.6.1.3 requires the affected i
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' l 1-flow paths to be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or the plant placed in Mode 3 (Hot Shutdown) in i
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. TS LCOs for neither cf the valves were entered as required by Operations i
Secticn Procedure.OSP-0040, "LCO Trackina and Safety Function Determination Program," Revision 2. By 9:30 a.m., powe; mis restored to the valves and they were shut. The valves wem inopeiable for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 15 minutes and, therefore, the plant was not u a cond@ prohibited by the TS. The operators initiated a CR to enter this item into the licensee's corrective action system.
l The inspector.s discussed this item with the Operations Superintendent, who stated that the tagging official and operating crew did not recognize that the two valves were containment isolation valves. The licensee stated it was acceptable to allow work on a valve being used as the containment isolation boundary, but the normal practice was to use an upstream valve to isolate the penetration for containment isolation purposes. If the valve being worked was the isolation boundary, the licensee would shut and deactivate tl o valve and. allow operation of tne valve for retesting under administrative controls per TS 3.6.1.3.
For corrective actions the licensee planned to revise Operations Section Procedure OSP-0038, " Protective Tagging Guidelines," Revision 3, to list examples of lesson-s learned from deficient clearances implemented for MOVs (i.e., considerations for manual containment isolation valves or valves that may change position during maintenance).
The individuals were counseled on their fundamental license responsibilities to recognize i
all TS LCO cond;tions when removing equipment hom service or an equipment failure n
occurred. Shift briefings were being developed for all shift crews and the work control staff on the lessons learned and implications of this event. The licensee commenced an ewtuation _of when similar clearances were implemented, which was typically near the end of the night shift when there was a lot of activity preparing for watch relief and setting up to support the day's scheduled maintenance activities. The licensee was considering adding more prominent visual aids on the main control room panels to identify manual containment isolation valves, such as the two valves discussed above. Finally, the licensee scheduled a Corrective Action Review Board to address this issue to ensure all of the root causes were addressed in the corrective actions.
The failure to document entry into TS LCO 3.6.1.3 in accordance with Procedure OSP-0040 is a violation of TS 5.4.1.a. However, this licensee-identified and corrected violation is being treated as an NCV consistent with Section Vil.B.1 of the NRC Enforcement Policy. Specifically, the violation was identified by the licensee and was not willful, actions taken as a result of a previous violation shoulc not have corrected this problem, and appropriate corrective actions were com%eted by the licensee (50-458/97008-01).
c.
Conclusions An NCV was identified for failing to enter to enter TS LCOs for two containment isolation valves. - The tagging official and the operators did not fecognize that the two valves were containment isolation valves. The operators identified the discrepancy within the time allowed by the TS to shut down the plant.
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O1.3 Manual Scram Uoon Loss of Two Reactor Feedwater Pumos a.
Insoection Scoce (93702. 37551. 71707)
The inspectors observed and reviewed the operator and equipment response to the May 6,1997, event when the reactor was manuclly scrammed following the loss of power to two of the three reactor feedwater pumps. The inspectors also evaluated the licensee's root cause analysis report and post-scram report generated by Operations.
b.
Observations and Findinas At 9.02 a.m. on May 6, a reactor operator manually scrammed the reactor in anticipation of an imminent reactor vessel Level 3 automatic scram, because electrical power had been lost to Reactor Feedwater Pumps B and C. The remaining Pump A could not sustain reactor vessel water level with the plant operating at full power, nor was it designed to do so. The operators entered the appropriate emergency and abnormal operating procedures. All engineered safety feature systems responded, as designed, and offsite power was not lost or degraded during this event.
Onsite power Breakers NPS-ACB27, NNS-ACB15, and ENS-ACB26 tripped as a result of j
the loss of voltage on 13.8-kV nonsafety-related Bus B,4.16-kV safety-related Bus B, and two 4.16-kV nonsafety-related busses, one of which supplied power to the safety-related high pressure core spray bus. The Divisions ll and til emergency diesel generators (EDG) automatically started and restored safety-related powe to their respective busses; however, loss of the nonsafety-related busses resulted in the loss of reactor recirculation
' Pump B and nonsafety-related power to reactor protection system (RPS)
Motor-Generator B. The loss of the motor-generator set resulted in certain containment isolation valves shutting, such as cooling and purge water to the reactor recirculating pump seals.' The operators then secured reactor recirculating Pump A to minimize damage to the seal. This action placed the reactor in natural circulation cooling. The operators maintained reactor pressure vessel water inventory using reactor feedwater Pump A and controlled pressure using the safety / relief valves. The lowest reactor water level recorded was -18 inches, which was about 12 feet above the top of active fuel, t
Sinco some of the steam loads could not be isolated because of the power losses, the operators closed the outboard main steam isolation valves to prevent exceeding the maximum allowed cooldown rate.
The operators responded well to this event, considering the obstacles encountered. They worked as a team, and communicated well. The control room supervisor maintained good command and control; however, his articulation of goals and prionties to the crew was not as frequent and as clear as had been observed at other events at River Bend in the past.
Besides the task of understanding what had occurred with the onsite power sources while shutting down and stabilizing the plant, the operators were challenged by the inability to restore RPS B power through normal means so that the containment isolation valves could be reopened and the affected systems restored. RPS B electrical protection assembly (EPA) Breaker H would not close to connect safety-related power to RPS B via t
l j
4 the power line conditioner. Because the EPA undervoltage relay reset point overlapped the normal output voltage of the power line conditioner, the EPA could not be reset. This was exacerbated by the control room operators discovering that they could not manually control EDG voltage to compensate for the voltage overlap with the EPA. Subsequent troubleshooting revealed a failed relay in the EDG manual voltage control circuit, which was replaced prior to startup. Although this failed relay complicated the scram recovery, the relay had no effect on the ability of the EDG to perform its intended safety function to start and automatically load the bus at rated voltage and frequency.
The inspectors later observed the change of the EPA reset point to eliminate the overlap problem with the power line conditioners. The more significant challenges encountered by the operators as a result of this EPA probiern were as follows:
Reactor recirculating Pumps A and B seal purge and cooling remained isolated long enough for the seals to reach abnormally high temperatures, which increased the probability of elastomer seal ring damage. As a precaution, the licensee replaced the Pump B seal and inspected the elastomers. Pump B was ' selected because the licensee noted higher temperatures than on the Pump A seal. There was no damage on the Pump B seal, so the Pump A seal was not replaced.
Because reactor water cleanup and shutdown cooling was also isolated, and since no forced circulation was available, this resulted in an uneven cooldown of the reactor. The differential temperature between the bottom head and the steam dome exceeded 100 F and prevented a subsequent reactor recirculating pump start once RPS power was restored and the isolation was cleared.
Drywell sump drains were isolated, preventing containment sump pump operation and invalidating leakage monitoring in the drywell.
Nonsafety-related chilled water to the containment unit coolers remained isolated, a
complicating containment pressure control.
At 1:59 p.m. on May 7, the plant entered Mode 4 (Cold Shutdown). The licensee commenced a forced outage and repaired FCV B (discussed in Section M1.3 below),
replaced the reactor recirculation Pump B seal, replaced a failed weld on the FCV B vent valve (discussed in Section M1.2 below), replaced leaking packing on inboard Main Steam Isolation Valve (MSIV) B, and accomplished cold shutdown surveillance tests.
The licensee implemented a SERT to investigate the causes and effects of the scram. On May 12, the SERT issued a well written, detailed report that was reviewed by the inspectors. The SERT determined that workers performing an authorized modification severed and shorted two conductors in a cable while removing low density silicon elastomer from a cable penetration in the turbine building floor. The shorted conductors actuated two lockout relays, which in turn tripped three breakers supplying power to the River Bend busses. When the workers removing the elastomer reached a depth of about 14 inches, the lights went out in the turbine building. The workers stopped and found the end of a cable in the hole. The workers promptly notified the control room, an operator in
~
-S-the turbine building, and an electrician of the potential for a cut cable. This action facilitated the determination of the cause of the scram; however, the SERT questioned the controls for breaching penetrations.
The SERT found that there was no site standard, procedure, or formal guidance for breaching a penetration. The tools to be used, the method bl digging, placement of the hole, and how close to come to the existing cable tray were either communicated informally or left to the skill of the craft. The work package had a single line instructio1 which read, " Breach Seal H2F01 to accommodate the addition of a 3/4 inch diameter electrical cable in Cable Tray 1TC445N." The accepted tools used consisted of a ball peen hammer and a screwdriver to dig out the elastomer. In the view of the SERT, the large number of penetrations breached without incident over the past several years led the licensee to have a high comfon level with the methods used and the risk imposed when breaching penetrations with existing cable runs. The above work package was not recognized as a high risk activity by those involved with the planning and authorization of the work.
For immediate corrective action, the Plant Modification and Construction Group informed the inspectors that they would not breach any more penetrations containing unprotected electrical cable or internal conduit seals until individuals performing the breach were trained on the use of nonmetallic tools and the cable identification (impact) and breach location have been identified in a formal Enoineering Request. For the long term, the j
licensee indicated that a formal procedure was being developed to prescribe methods for j
safely breaching penetrations and removing penetration material using tools that will not damage cables.
l Prior to startup, the inspectors examined the post-scram report and found no
)
discrepancies. On May 14, the plant entered Mode 2 (Startup), and achieved full power operation on May 20. The inspectors observed portions of the startup activities and noted good performance on the part of the operators. The startup was conducted in a safe, j
deliberate manner in accordance wi'h the applicable operating procedures. Unidentified j
drywell leakage was successfully reduced from aprroximately 2.6 gpm to 0.1 gpm as a i
result of leak repairs.
c.
Conclusions The operators responded well to the May 6 loss of two reactor feedwater pumps by manually scramming the reactor in anticipation of an automatic scram on low water level in the reactor vessel. The licensee's staff also demonstrated good teamwork as they dealt with the complications caused by the loss of power.
The workers who inadvertently cut and shorted a control cable while breaching a penetration in the turbine building facilitated a timely determination of the cause of the scram on May 6 by promptly informing the control room when the lights went out.
l L'
l l The SERT issued a thorough and comprehensive root cause analysis report after investigating the scram of May 6. The root causes and corrective actions were appropriate to the circumstances.
-02 Operational Status of Facilities and Equipment O2.1 Drvwell Walkdown a.
Inspection Scope (71707)
On May 13,1997, at the conclusion of a forced outage, the inspectors toured the drywell with licensee management to verify that the plant was ready for plant startup.
b.
Observations and Findinas The inspectors noted that the housekeeping in the drywell was good, with the exception of a few pieces of tape floating in the suppression pool and a rag and a pad duct-taped to a support at lower elevations of the drywell. Licensee management thoroughly examined all e
areas to ensure that loose debris was removed such that the operability of the emergency core cooling systems would not be challenged by clogged suction strainers.
During the tour, the inspectors noted that Valve 1E12*FO10, a manual isolation valve in the residual heat removal (RHR) system, was locked open in a questionable manner.
Valve 1 E12*FO10 was locked using a heavy chain and lock with the chain attached to the valve's handwheel and a nearby structural support and conduit. The inspectors were concerned that this configuration rnay have established an unanalyzed res;raint on the RHR system or could result in riamage to the conduit, during any movement of the RHR piping. The licensee relocked ine valve such that the chain was attached ta the valve handwheel and yoke, thus removing the questionable restraint. The licensee initiated a CR to enter this problem into the corrective action program.
The inspector discussed this observation with the Mechanical Design Engineering Manager, who stated that Valve 1E12*FO10 was improperly locked from a mechanical design perspective. The inspector noted that licensee procedures did not provide direction as to prohibited practices for locking valves. The licensee stated that they depended on " common sense" that operators would never lock and chain a valve to structural supports or other safety-related equipment. However, because of the issue with Valve 1E12*FO10, the licensee initiated a revision to Operations Section Procedure OSP-0014, " Administrative Control of Equipment and/or Devices," which provided
' direction for locking valves. The inspectors considered the licensee's actions appropriate L
.to resolve the valve locking issue, which was of relatively minor safety significance.
c.
Conclusions Housekeeping in the drywell prior to startup from a forced outage was good, with minor exceptions. Operators inappropriately locked and chained a valve to a structural support 4
{.
.l l
f and conduit such that the chain could become an unanalyzed restraint. Although engineering personnel recognized that this was an unacceptable practice, no formal direction or training was given to operators to prevent improper locking of valves until this issues was identified.
02.2 Failure to Maintain On-Line Risk Monitor a.
Inspection Scope (71707)
During routine tours, the inspectors reviewed a sample of the licensee's actions to evaluate the effect on risk of removing safety-related equipment from service, b.
Observations and Findinas On April 23,1997, the inspectors noted that on April 21, the licensee had removed several safety-related components from service to perform on-line maintenance. The operators removed Division i of the control room air conditioning system, RHR Train A, and a bank of standby service water cooling tower fans from service concurrently to support the preventive maintenance schedule. The licensee's SEA Group had performed a quantitative risk assessment during the previous week and determined that the plant would be in " condition ye!!ow," which meant the configuration represented an " acceptable risk."
However, when the equipment listed was removed from service on April 21, the shift technical advisor (STA) performed a real-time risk assessment using the control room EOOS monitor. This time the EOOS monitor output stated that the plant was in " condition orange," which meant that the plant configuration represented "high risk." Licensee procedures required senior management approval to enter " condition orange" and required the operators to take compensatory actions and protect the operable redundant safety trains. These actions were not taken. The STA contacted the SEA group, who informed the STA that the control room EOOS monitor was incorrect and that the computer used by the SEA group provided the correct risk assessment; therefore, no further action was required. The SEA group later explained that the EOOS monitor modeled the pregenerated cut sets in error and, later on April 21, they changed the EOOS computer to model the regenerated cutsets, which brought the computers into agreement.
l The inspector questioned the licensee as to why they did not take the more conservative action prescribed by procedures when in " condition orange" when a conflict arose l
between the SEA and the control room EOOS monitor. The licensee stated that the EOOS monitor in the control room was considered a backup to the official risk monitor operated by SEA personnel.
The inspectors noted that " River Bend Station On-Line Maintenance Guidelines," Revision 0, described the licensee's process for on-line risk monitoring. The SEA group was required to perform the risk assessment the week prior to the work occurring, during the
- planning stages. However, if emergent work or delays resulted its plant configurations that were not anticipated in the work week planning stages, the STA was required to use the
8-I EOOS monitor in the control room to ensure that the risk was acceptable or the proper actions were taken. These actions could be necessary on backshifts and weekends when
)
the SEA group was not present. Therefore, the licensee took credit for the EOOS monitor in the control room to meet the risk assessment requirements in the maintenance rule.
On April 30, the inspectors questioned the licensee as to why the administrative feature
]
concerning which modeling techniques to use were not the same for both the EOOS i
monitor and the SEA computer. The SEA group could not explain how this administrative l
level feature had been changed but explained to the inspectors that changing back to regenerated cutsets brought the EOOS computer in line with the SEA computer. To preclude a repeat of this problem, the SEA group added a precaution to the on-line maintenance guidelines for EOOS users not to change administrative level features without consulting the SEA group first.
c.
Conclusions The licensee did not adequately maintain the capability to quantify plant risk in that the EOOS monitor used by control room personnel contained an incorrect risk model.
O3 Operations Procedures and Documentation O3.1 Reactor Recirculation FCV B Continoencies a.
Inspection Scoce (71707)
The inspectors reviewed the licensee's contingency plans for operating the plant with
. reactor recirculation system FCV B locked in the open position to ensure that these plans were consistent with regulatory requirements.
b.
Observations and Findinos The licensee developed contingencies to operate with FCV B locked open so that operators would be familiar with the alternate actions to be taken when abnormal procedures directed the operators to rapidly decrease reactor power with the FCVs.
The inspectors noted that the contingency for loss of the bus duct cooling fan required a rapid reduction in power using FCV A. With FCV B locked open, this action would result
. in a mismatch of flow between the two recirculation loops. TS 3.4.1 requires loop mismatch to be maintained within 5 percent when reactor power is greater than or equal to 70 percent and the mismatch must be within 10 percent when reactor power is less than 70 percent. Step 7 of this contingency stated that if loop flow mismatch requirements could not be met within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, then enter TS 3.0.3. However, the inspectors noted that TS 3.4.1 requires the licensee to secure one recirculation pump if matched flow cannot be restored within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.. The inspectors noted that the basis for TS 3.0.3 states that entry
. into TS 3.0.3 shall not be used for operational convenience.
0 9
The inspectors discussed this observation with the Operations Manager, who initially stated that entering TS 3.0.3 for loop flow mismatch problems would facilitate recovery of the plant following a loss of bus duct cooling. Later the Operations Manager stated that the contingency plan was not a procedure on how to manipulate the plant, but a listing of the potential challenges operators may face. The contingencies were developed and documented only to help oversight groups to determine if continued operation with FCV B locked open was prudent.
Although licensee management stated that these contingencies were not procedures, the contingencies were kept on the control room supervisor's desk and in the at-the-controls area in the control room for quick reference by the operating crews. In addition, the contingencies contained several "if.. then" statements, which appeared to be providing direction.
The licensee did not use any of these contingencies because on May 6,1997, the reactor was manually scrammed as discussed in Section 01.3 of this report. During the forced she'down following the scram, the licensee repaired and retested FCV B, so the operational contingencies were not necessary. Although the contingencies were not used, the inspector concluded that, if the contingencies had been followed as written, the licensee would have operated nonconservatively and not in accordance with the TS.
c.
Conclusions Contingency plans for operating with FCV B locked open contained apparent direction that conflicted with the TS. Licensee oversight groups that reviewed the evaluation to support operation with FCV B locked open did not perform sufficiently detailed reviews to identify the conflict.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments on Maintenance Activities a.
Inspection Scope (62707)
The inspectors observed portions of work activities covered by the following maintenance action items (MAI):
MAI P594145: Replace low pressure core spray pump output breaker (May 2, 1997).
MAI 311255: Troubleshooting and repair of reactor recirculation system flow control Valve B (May 8-12).
b.
Observations and Findinas
. The inspectors found the work performed under the above listed MAls to be professional and thorough. Maintenance technicians demonstrated good foreign material exclusion practices and good attention to detail by following the work instructions and peer checking.
The technicians were experienced and knowledgeable of their assigned tasks. The inspectors frequently observed the presence of supervision and system engineers j
monitoring job progress and resolving questions. Appropriate clearances were utilized for personnel and equipment safety and the operators entered the correct TS LCOs.
M1.2 Failure of Heactor Coolant Pressure Boundarv Weld a.
Inspection Scope (62707) l 1
The inspectors reviewed the licensee's actions following discovery of a cracked and leaking weld on a vent valve located on reactor recirculation system FCV B.
b.
Observations and Findinas Prior to the scram of May 6,1997, the licensee had been monitoring unidentified drywell i
leakage for several months as it slowly trended upward from approximately 0.5 gpm in November 1996 to approximately 2.6 gpm on May 5,1997. Engineering analyzed drywell drain sump samples, drywell unit cooler condensate flow, and drywell atmospheric particulate and gaseous monitor indications and determined the most probable location of the leak to be the stem packing on inboard MSlV B. This was further supported by the fact that this packing gland had to be adjusted during the previous startup.
During the drywell walkoown that followed the scram of May 6, MSIV B packing was found
. to be leaking but, in addition, a small leak was found spraying from the socket (fillet) weld at the inlet of the cent valve on FCV B. The weld was reported to be leaking about 180 around the circumference. The vent valve was connected to the top of the bonnet on FCV B by a 3/4-inch pipe about 4 inches long. This was a single valve backed up by a i
threaded pipe cap on the downstream side. The valve was made of SA-182, F316 stainless steel. The connecting pipe material was SA-312,316L stainless steel. The inspectors reviewed the installation detwnentatior (Maintenance Work Order R164796) dated May 10,1994, when this valve was last replaced because of seat leakage. The documentation was in order and reflected the appropriate quality assurance involvement.
The weld material requisition correctly specified the filler metal to have been ER316L stainless steel.
When the maintenance worker removed the pipe weld to the FCV B bonnet and attempted to break the removed weld loose to remove the valve assembly, the defective weld failed the rest of the way. The licensee took the assembly to the shop and examined the failed weld visually and by a microscope. The weld metal was cracked through the full thickness at the throat of the weld in a jagged plane from the throat to close to the root of the weld.
The weld had failed circumferentially about 240. On the request of the inspectors, the l
licensee determined the weld to be nonmagnetic, which was a simple test to support the weld installation documentation.
l l
- l The licensee speculated that the most likely causes of the weld failure could have been a weld defect (i.e., solidification cracking or inclusions) or possibly weld chemistry. The licensee further speculated that, because this particular weld was severely ground on, the l
grinding marks may have masked a surface defect that otherwise may have been detected by liquid penetrant testing. The licensee stated that the above possible failure mechanisms can only be determined by a metallurgical laboratory licensed to handle radioactive material. The failed weld could not be decontaminated for unrestricted j
handling. As of the end of this inspection period, the licensee was in the process of contracting a laboratory. The inspectors will follow up on the licensee's determination of the root cause of the weld failure and this issue will be tracked as an inspection followup j
item (IFI) (50-458/97008-02).
The licensee performed a 20 percent sampling of other vent valves by visual and liquid penetrant testing. This translated to 7 reactor coolant system and 5 others out of a 1
population of 52 vent valves. No heavy grinding was present on the other welds and the liquid penetrant examination showed no evidence of cracking. This was a reasonable approach to ensure there were no other failed vent valve socket welds, pending the root cause determination.
c.
Conclusions The licensee's approach to the weld failure on the FCV B vent valve was appropriate to the circumstances. An IFl was identified to follow up on the final root cause determination.
M1.3 Repair of Reactor Recirculation System FCV B a.
Insoection Scope (62707)
The inspectors observed portions of the work and diagnostic activities associated with the repair of FCV B under mal 311255.
b.
Observations and Findinas Discussion on the problem with FCV B locking up was documented in NRC Inspection Report 50-458/97-007, Section M1.2. The licensee originally justified continued operation until the September 1997 refueling outage; however, the May 6 scram afforded the licensee the opportunity to repair the valve.
Prior to the forced outage provided by the scram, engineering and maintenance personnel had conducted extensive troubleshooting of the FCV B hydraulics and concluded that the problem rested within the valve internals. The hydraulic actuator appeared to be trying to move the valve stem, but could not. During the outage, disassembly of the upper bonnet of FCV B permitted visual and dimensional checks. There was no damage to the lever, link, pins, or valve body. Two broken metallic pieces were found lying in the bottom of the upper valve cavity, which were later identified as part of the stellite liner of either the guide sleeve or guide piston. To keep the lateral stresses off the packing gland, the valve was equipped with a guide piston that absorbed all but the longitudinal forces of the actuator.
j l
i l
- -. - ~ _ ~
. - ~ - - - -
j !
. The piston had a stellite liner, as did the cylinder in which the piston travelled. The guide i
l piston was incide the pressure boundary of the upper bonnet of the valve. After removal J
of the guide cylinder / piston assembly, two more small pieces of liner material were found.
1 l
With the actuator and lever disconnected from the valve stem, the valve moved freely.
l l
When checking for dimensions and clearances, the mechanics found no anomalies except I
l the vertical thrust bearing clearance was 0.025 inch, when 0.010 inch was specified.
l Because the thrust shoes were the correct thickness (i.e., showing no measurable wear),
the licensee concluded that the previous installation was not correctly done. This additional clearance should not have caused the broken liner.
The licensee determined the cause of FCV B locking up was the broken pieces of stellite i
jamming the guide piston, thereby preventing movement of the valve. FCV B had binding problems during the previous fuel cycle when the plant began operating with increased reactor coolant flow. The valve would not open past 95 percent. During the subsequent refueling outage, the mechanics found the actuator misaligned. This was corrected, but the misalignment may have caused excessive forces to develop between the guide piston and the guide cylinder liners, subsequently cracking the liners. The licensee stated that it j-was also possible that the stellite had material deficiencies.
After the valve was reassembled with a new guide piston and cylinder, the valve operated l
normally and satisfactorily. As described below, the operational test was performed i
without any problems. Because of the need to keep radiation exposure ALARA, the L
licensee chose not to handle the broken parts of the valve because they were highly radioactive. Therefore, the root cause of what mechanism resulted in the breaking of the stellite liners would not be determined. The worst case scenario with a repeat failure l
would be for the valve to lock up again, and locking up is the only safety function the valve has other than limited speed of operation. The licensee has already demonstrated the ability to cope with a locked up FCV.
L l
Throughout the planning, troubleshooting, and repair of FCV B, plant personnel i
demonstrated a good sensitivity to keeping exposures ALARA through frequent briefings and the use of mockups. Another FCV was set up in the shop so that the mechanics could practice activities to be performed in the high radiation area of FCV B. Work at the jobsite was difficult from an accescibility standpoint and the valve parts were heavy l
requiring rigging. Engineering, vendor, and radiation protection support was well provided l
and the overall approach to the troubleshooting and repair of FCV B was methodical and l.
minimized unnecessary work.
c.
Conclusions Plant personnel demonstrated excellent performance in the planning, troubleshooting, and repair of reactor recirculation FCV B. Exposures were kept ALARA through the use of
)
mockups and frequent briefings.
i j
. M1.4 Surveillance Observations a.
Insoection Scope (61726)
The inspectors observed all or portions of the following surveillance tests during this inspection period:
STP-053-0601:
Reactor Recirculation FCV B operability test (May 13,1997).
^
STP-500-4503:
Reactor Protection System Scram Discharge Volume Water Level High, Channel Functional Test (June 1)
STP-500-4521 Rod Pattern Control System Scram Discharge Volume Water Level High, Channel Functional Test (June 1) b.
Observations and Findinas The inspectors found that the surveillance tests listed above were conducted properly and meaningful results were obtained. Self-checking and peer checking was evident when it was appropriate to do so. During independent verification, the verifiers demonstrated a conscious effort to maintain independence from the performers. TS LCOs were entered when required. Measuring and test equipment was verified to have been in calibration.
The inspectors reviewed the completed test documentation and noted that it was legible and all acceptance criteria were met, c.
Conclusions The surveillance tests observed during this inspection period were performed properly and in accordance with the applicable procedures.
O M4 Maintenance Staff Knowledge and Performance M4.1 Clearance Order Process Errors l
a.
Inspection Scoce (62707)
The inspectors reviewed the licensee's response to CR 97-0603, which identified an adverse trend in the clearance process. Three instances occurred where clearance orders were improperly implemented and could have adversely affected plant operations or personnel safety.
b.
Observations and Findinas CR 97-0603 identified an adverse trend in the clearance order process. The individual events discussed in CR 97-0603 were as follows:
l i
k 14 On March 22,1997, the control room received an annunciator alarm for low scram air header pressure. Investigation revealed that mechanics were attempting to tighten a joint at Hydraulic Control Unit 40-53 that had a minor air leak. In order to tighten the leaking pipe fittings, the union had to be loosened because of the piping configuration. When this was done, this greatly increased the leakage and resulted in the low scram header pressure alarm. The mechanics quickly retightened the union to stop the increase in leakage. If the scram air header pressure had continued to decrease, operators would have been required by procedure to insert a manual reactor scram. During the work planning process, maintenance personnel failed to recognize that, in order to tighten the leaking joint, the union had to be loosened. Therefore, this task was performed without a clearance order and was assumed to be minor work that did not entail high risk.
Had the scope of the work been properly communicated to the work management center, a formal clearance order would have been used in conjunction with an Engineered Safety Feature / Reactor Protection System Potential actuation sheet to alert the craftsmen to the high risk of the activity. This event was the first example of a violation of TS 5.4.1.a for failing to implement Administrative Procedure ADM-0027, " Protective Tagging," Revision 16.
On April 17, while working on the actuator for Valve G36-AOVFO148 (reactor water cleanup filter demineralizer service air supply isolation), the valve packing was expelled and the mechanic was sprayed in the face with radioactively contaminated water. The licensee investigation revealed that this event also was a result of failure to communicate the full scope of the work.
Following discussions between the work management center and maintenance personnel, they determined that the actuator work was minor in nature and could be perf;rmed without a formal clearance. A prejob briefing was conducted that apparently confirmed this decision. Operators closed the valves adjacent to Valve G36-AOVFO14 to prevent unanticipated problems with the reactor water cleanup system. However, upon arrival at the job site, the mechanics noted that the vendor manual (referenced by the MAI) required that the valve packing flange must be removed to remove the actuator. The mechanics did not recognize that this was an increase in the understood scope of work and was a breach of the reactor water cleanup system pressure boundary. As the mechanics began to loosen the packing flange, the packing was expelled and a mechanic was sprayed with contaminated water. Procedure ADM-0027 and Operations Section Procedure OSP-0038, " Protective Tagging Guidelines," Revision 3, required a formal clearance order with two-valve isolation and a vent path in between for work that breached a pressure boundary in which the pressure of the system was greater than 500 psi. The failure to implement the requirements of Procedures ADM-0027 and OSP 0038 was the second example of a violation of TS 5.4.1.a.
On April 23, a near miss occurred as mechanics were preparing to lubricate the coupling of Pump EGO-P1 A (Division I EDG lube oil keep warm pump) and the pump automatically started. Pump EGO-P1 A was required to be formally tagged
- - - - -. =, _.
l 1
l l
l 1
out for this task. The mechanic contacted control room personnel, who initiated a human danger tag to allow completion of the work.
F Subsequent licensee investigation revealed that mechanical maintenance personnel submitted a request for a clearance order that entailed several systems and work that was largely unrelated. The licensee's electronic work management system allows one work package to be the lead work package, with additional work being processed as an attachment. The clearance request for work on Pump EGO-P1 A was submitted as an attachment to a request to work on a fuel oil strainer. The Operations tagging official did not review the attachments to the lead l
clearance request when preparing the tagout, only printed out the lead request, l
and then deleted the electronic copy. A second tagging official reviewed and approved the clearance with the deficient information provided by the first tagging l
official.
l After receiving the clearance receipts for the preventive maintenance tasks to be performed, the mechanical maintenance supervisor failed to ensure that clearance orders had been prepared for all of the work to be done. In addition, the mechanical maintenance supervisor did not walk down the tagout prior to the work.
Therefore, the supply breaker for Pump EGO-P1 A was not opened and tagged and the pump was lined up for automatic operation. The inspectors concluded that it was fortuitous that the pump started and the mechanics recognized the clearance order error before commencement of the work. The failure to provide an appropriate clearance order for work on Pump EGO-P1 A was the third example of a violation of TS 5.4.1.a.
j Separate CRs were initiated on each of the above occurrences. On May 1, the licensee recognized that a potential adverse trend in the implementation of the clearance order l
process existed and CR 97-0603 was written. The licensee noted that some craftsmen were becoming complacent in performing what they perceived to be routine work and were not sufficiently sensitive to the risks associated with work at a nuclear facility. In addition, the licensee noted that improvements were necessary in the electronic maintenance systems such that the tagging officials would be cognizant of all required work and clearance orders. A Corrective Action Review Board was convened.
i For corrective actions, the licensee: (1) modified the electronic maintenance system to allow all work to be performed on a clearance request to be printed out together, (2) briefed operations and maintenance personnel on the requirement to follow the clearance process no matter how innocuous the task seems and the importance of communicating to operations the complete scope of work, (3) took appropriate disciplinary action, and (4) revised the initial training modules for operations tagging officials and maintenance clearance holders on the electronic maintenance system and the clearance process.
The above three examples of failing to appropriately implement the clearance order process of Procedure ADM-0027 constitute a violation of TS 5.4.1.a. However, this licensee-identified and corrected violation is being treated as an NCV consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the violation was identified l
e by the licensee and was not willful, actions taken as a result of a previous violation should not have corrected this problem, and appropriate corrective actions were completed by the licensee (50-458/97008-03).
c.
Conclusions A noncited violation was identified for three examples of failing to properly establish clearances for work isolation. Personnel in operations and maintenance failed to communicate properly and follow procedures, which led to these three occurrences. The licensee appropriately recognized that an adverse trend in establishing clearance boundaries existed and initiated a trending CR.
M8 Miscellaneous Maintenance issues M8.1 (Closed) IFl 50-458/96015-04: Review of all safety-related MOVs to verify that the calculated design basis differential pressure for each valve was comparable to the actual conditions anticipated during normal operation, accident conditions, and anticipated transient conditions as required by Generic Letter 89-10, " Safety-Reiated Motor-Operated i
Valve Testing and Surveil!ance."
On October 24,1996, while performing inservice stroke testing of standby service water valves, manual containment isolation Valve SWP-MOV81B failed to fully close. The thrust set into the valve was insufficient to overcome the valve differential pressure. This was i
because the thrust was calculated on the basis of a design basis differential pressure that was less than the valve actually experienced. Although the specific problem was resolved, the inspectors questioned whether there were other valves with similar discrepancies.
The licensee performed a detailed review and documented the results in Engineering Request 97-0018, "GL 89-10 MOV DP Scenario Review." The report identified 23 MOVs that had design basis differential pressures less than the differential pressures that could be experienced during testing or operation. However,22 of the 23 valves either had sufficient actual thrust values set in, based on test data, to accommodate the additional differential pressures without damaging the valves, or the increased value applied only to the nonsafety direction of valve movement. The licensee already initiated action under CR 96-0931 to recalculate the design basis minimum thrust for these valves to ensure the actual thrust set in during future testing and maintenance will remain adequate to overcome the expected differential pressures. Main steam isolation valve drain isolation Valve B21-MOVF086 did not have sufficient thrust set in to overcome full main steam pressure; however, the valve would only be subjected to full main steam pressure if the normally closed d.ownstream valves were opened. Furthermore, Valve B21-MOVF086 had a single safety function to be closed manually 20 minutes after a loss-of-coolant accident to enable the main steam positive leakage control system to seal the valve.
During this scenario main steam pressure would be low enough for the valve to overcome the differential pressure,if any existed. The licensee submitted a license amendment to eliminate the positive leakage control system. If approvalis granted, the licensee
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~ indicated an intent to remove the valve from the GL 89-10 program, because it will no l
longer have a safety-related function.
1 Engineering Request 97-0018 also identified a listing of valves that currently did not have differential pressures higher than the design basis. This list was transmitted to Operations to advise them that changes in the expected differential pressure could result from changes in procedures and that personnel changing procedures must be sensitive to this potential problem.
111. Enoineering E1 Conduct of Engineering E1,1 Inaoorooriate Damper Alianment for SGTS Testina a.
Inspection Scope (37551)
The inspectors reviewed the engineering actions in response to CR 97-0526, which identified the conduct of secondary containment drawdown testing with an inappropriate damper alignment.
b.
Observations and Findinas On April 15,1997, while addressing a concern (documented on CR 97-0281) over difficulties encountered by plant personnel opening the auxiliary building secondary containment doors while the SGTS was in operation, the licensee identified a discrepancy in the damper alignment specified and used for drawdown surveillance testing of secondary containment as required by TS Surveillance Requirement 3.6.4.1.4. This test verified that SGTS will reduce (i.e., draw down) the ambient atmospheric pressure in the shield building annulus and the auxiliary building to at least a vacuum of 0.5 and 0.25 l
inches of water gauge in no more than 18.5 and 13.5 seconds, respectively. The applicable procedures specified a normal SGTS damper alignment for the test, which included having the SGTS fan recirculation dampers in their normally closed position. The recirculation dampers (GTS-AOD22A/B) were placed in the system to allow reduction in
{
the vacuum in the auxiliary building, thereby allowing easier access through the doors.
However, the dampers were designed to fail open on loss of instrument air, and thus the drawdown surveillance test had been conducted in a nonconservative manner. The TS acceptance criteria were met only with the recirculation dampers closed, calling to question SGTS capability to draw down the buildings within the specified time limits when the recirculation dampers were in the failed open position.
i The licensee promptly closed the manual balancing dampers (GTS-DMPSA/B) to ensure operability and to keep the SGTS in the as-tested configuration until the problem could be resolved. The balancing dampers were in the same flow path as the recirculation dampers, thereby eliminating the recirculation path that would otherwise be set up on a loss of instrument air. The inspectors expressed concern that this was an acceptable
)
.l
, immediate corrective action for the short term; however, it did not solve the original problem of personnel access to the auxiliary buildir.g with the high vacuum exerting an opposing force on the doors. The licensee was reluctant to perform the drawdown test at power because it would place the plant in a 4-hour shutdown LCO in accordance with TS 3.6.4.1. This issue became moot when the plant was manually scrammed on May 6.
After the plant was shut down, the licensee performed a series of tests demonstrating that, with the balancing dampers in the position they were in prior to closing them and with the recirculation dampers open, the SGTS could not draw down the auxiliary building within the specified 13.5 seconds. This was not a problem with the recirculation dampers kept j
closed in accordance with the system operating procedure, but would have been if the recirculation dampers failed open on loss of instrument air. However, further testing j
revealed that the instrument air accumulators would have held the recirculation dampers 1
closed long enough for SGTS to draw down the auxiliary building within 13.5 seconds.
The accumulator boundary valves were not in the inservice test program; however, the i
accumulators had no safety function. Therefore, the licensee could not take credit for the accumulators to maintE.in the recirculation dampers closed.
The licensee balanced the SGTS with the recirculation dampers open and revised Procedures STP-257-0601 and -0602, "SGTS Train A(B) Drawdown Test," to require testing with the recirculation dampers open. On May 11, both Trains A and B SGTS were tested and met the TS acceptance criteria. The system operating procedure was also i
revised to require the recirculation dampers to be in automat lc instead of closed and, when running SGTS manually, the revised procedure required the operators to open the dampers to facilitate auxiliary building access.
The inspectors questioned how personnel would be able to gain access to the auxiliary building in the event of a control room evacuation. This scenario typically would result in a start of both trains of SGTS with one of the recirculation dampers closed from a short circuit caused by a fire. The licensee initiated CR 97-0703 to address this issue. The 5
licensee's engineers calculated a potential force required to open the auxiliary building door to be 442 pounds. As an interim solution, the licensee staged rigging equipment (a "Cumalong") near the outside of the 95-foot elevation auxiliary building door for personnel to pull the door open enough to break the seal. Inside the door a crow bar was staged to facilitate egress from the auxiliary building. The licensee stated that this interim solution will be in effect until the vacuum can be reduced. This will require increasing the allowable drawdown time in the TS and the licensee indicated that there was sufficient margin available for a justifiable change to the TS.
Failure to maintain Procedures STP-257-0601 and -0602, "SGTS Train A (Train B)
Drawdown Test," Revisions 11 and 2, to adequately configure the SGTS for testing with the recirculation dampers open is a violation of TS 5.4.1. This licensee-identified and corrected violation is being treated as an NCV consistent with Section Vil B.1 of the NRC Enforcement Policy. Specifically, the violation was identified by the licensee and was not willful, actions taken as a result of a previous violation should not have corrected this problem, and appropriate corrective actions were completed by the licensee (50-458/96008-04).
l 4 c.
Conclusions Engineering demonstrated good attention to detail by identifying an inappropriate damper position applied during the auxiliary building drawdown test. An NCV was identified for failure to maintain an adequate surveillsnce test procedure. The interim engineering resolution of the auxiliary building access problem caused by high vacuum developed by operation of the SGTS was marginally acceptable.
IV. Plant Support P4 Staff Knowledge and Performance in Emergency Planning P4.1 NOUE Resultina from Drvwell Leakaae
. a.
Inspection Scoce (71750)
The inspectors reviewed the licensee's response to the manual reactor scram and followup drywell inspection on May 6,1997, with respect to emergency planning.
b.
Observations and Findinas On May 6,1997, following a manual reactor scram, the licensee inspected the drywell to locate the source of a 2.5 gpm unidentified leak as discussed in Section O1.2 of this inspection report. At 4:52 p.m. on May 6, while the plant was in Mode 3 (Hot Shutdown),
the licensee identified a weld leak on Valve RCS-V3003, which was a vent and drain valve on FCV B. The Shift Superintendent (SS) noted that this leak was from the reactor coolant pressure boundary as defined in 10 CFR 50.2. The SS recalled that, although Valve RCS-V3003 was in between the Recirculation Loop B isolation valves, the isolation valves had exh bited gross leakage in the past. Therefore, the SS reasoned that the weld leak at Valve RCS V3003 was pressure boundary leakage as defined in TS 1.1. The SS entered TS 3.4.5, which requires that, if pressure boundary leakage is detected in Mode 3, the plant must be cooled down to less than 200*F within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The SS believed that Emergency implementing Procedure EIP-2-001, " Classification of Emergencies," Revision 8, did not apply to this situation. The SS recognized that the licensee was required by Procedure EIP-2-001 to declare a NOUE if drywell unidentified leakage exceeded 5 gpm and, since drywell unidentified leakage was 2 gpm. the SS, in error, assumed that review of the emergency plan was not necessary to properly classify the event.
At 8:15 a.m. on May 7, during review of the previous day's events, the inspectors noted th'at the SS had determined that pressure boundary leakage existed. The inspectors reviewed Procedure EIP-2-001 and noted that Emergency Action Level 3 of Procedure EIP-2-001 required the licensee to declare a NOUE for exceeding any leakage limit in TS 3.4.5, including the identification of any pressure boundary leakage. Therefore, upon
i
. entry into TS LCO 3.4.5 the previous evening, the licensee was required to declare a i
NOUE and take the actions prescribed in the emergency plan.
The inspectors questioned the SS on this issue because the plant was still in Mode 3 (at approximately 265 F) on the morning of May 7. Because of the inspectors' concern, the SS reviewed Procedure EIP-2-001 and declared a NOUE at 9 a.m. on May 7. Upon properly classifying the event, the licensee made the necessary notifications in a timely manner. The licensee initiated a CR for failure to properly implement the emergency plan when required. The failure to properly classify the event and declare a NOUE upon determination that pressure boundary leakage existed is a violation of 10 CFR 50.54(q)
)
(50-458/97008-05).
The licensee continued to cool down the plant until the plant entered Mode 4 (cold l
shutdown) at 1 p.m. on May 7. The licensee exited the NOUE at that time.
i Following this event, licensee management determined that the SS designating the weld leak at Valve RCS-V3003 as pressure boundary leakage was a conservative decision.
The licensee wrote a position paper that stated that any leak between the recirculation loop isolation valves, by definition in TS 1.1, was not pressure boundary leakage regardless of the leak tightness of the loop isolation valves. The inspectors noted that the recirculation loop isolation valves were not safety-related, environmentally qualified, in the licensee's MOV program, in the inservice test program, leak tested, and did not have a rigorous preventive maintenance plan; therefore, the inspectors concluded that it was uncertain if these valves could be relied upon to isolate a leak.
c.
Conclusions A violation was identified for failing to properly classify and declare entry into a NOUE when operators determined that pressure boundary leakage existed. The inspectors prompted the licensee (approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> after the licensee initially identified the weld leak) to properly classify the event. The SS did not sufficiently review the emergency implementing procedures to identify the need to declare a NOUE.
S1 Conduct of Security and Safeguards Activities S1.1 General Comments (71750)
During routine tours, the inspectors noted that the security officers were alert at their posts, security boundaries were being maintained properly, and screening processes at the Primary Access Point were performed well.
F1 Control of Fire Protection Activities F1.1 Failure to implement Houriv Firewatch Tours a.
Inspection Scope (71750)
' The inspectors reviewed the licensee's actions in response to CR 97-0007, where a person designated to perform hourly fire watch duties failed to do so. The inspectors also reviewed the licensee's actions in response to subsequent CR 97-0707 where, again, j
hourly fire watch duties were not performed as scheduled.
b.
Observations and Findinas On January 6,1997, a security officer noticed a fire watch person present in the break room at a time when the fire watch tours were usually in progress. The security officer communicated this observation to his supervisor and the fire watch person was questioned. The fire watch person stated that he did not complete the 7 a.m. fire watch tours as required because he did not feel up to it and offered no valid excuse. Further review revealed that the fire watch route log had been completed and initialled by this fire watch person, indicating all areas assigned to him had been toured, when in fact the tours had not been completed. The inspectors reviewed the route log and noted that the 6 a.m.
and 7 a.m. tours were signed off by this fire watch person, as well as many others during the previous 2 months. Section 5.6 of Fire Protection Procedure FPP-0070, Revision 8, requires, in part, the fire watch person to visually inspect each area listed on the patrol fire watch route log.
The fire watch person was suspended pending further investigation by Corporate Security and CR 97-0007 was initiated. Key card histories were run on all fire watch personnel from November 1,1996, through January 6,1997, to determine if this fire watch person had failed to perform any other tours and to determine if any other personnel had failed to perform their tours. The key card histories confirmed that all other fire watch personnel j
were performing their tours as required; however, the fire watch person in question had
)
failed to complete 105 of the 305 tours he signed off as properly completed. Key card histories also revealed that Security supervisors had performea 198 tours or checks on fire vatches since November 1,1996, and in particular, four different supervisors accompanied this fire watch person on 13 tours to observe his performance. No anomalies with this individual had been identified.
Resoonsibility for the fire watch function had been transferred to Plant Security as of November 1,1996, when The Wackenhut Corporation provided new fire watch personnel to River Bend. The inspectors noted that fire watch personnel were trained and appropriately supervised. Expectations for performance of fire watch duties were clearly stated and were posted in the break room. However, there was no process in place to ensure that hourly tours were, in fact, performed as required.
The licensee considered this problem to have been an isolated case involving a single individual. The individual was terminated on January 8,1997. The I;censee's plant security superintendent instructed The Wackenhut Corporation to meet with fire watch personnel to reiterate the importance of their function and what to do if they could not complete their assigned tours.
l L; Multiple failures between November 1,1996, and January 6,1997, to complete fire watch tours as specified in the fire watch route log in accordance with Procedure FPP-0070 is a violation of TS 5.4.1.d (50-458/97008-06).
On May 13,1997, a 1 a.m. fire watch tour was not performed, in this instance, the nroblem was identified by security supervision upon reviewing the fire watch route log.
CR 97-0707 was initiated and the subsequent hourly tours were performed as scheduled.
The cause of this failure was that the normally assigned fire watch person was scheduled for a break and a fire watch qualified security officer was scheduled on the E-Shift l
Rotation Security Schedule to perform the tour. However, the security officer failed to read the schedule and, therefore, did not know he was to make the tour.
Failure to perform the required fire watch tour at 1 a.m., on May 13,1997, in accordance with Procedure FPP-0070 is a violation of TS 5.4.1.d. This licensee-identified and corrected violation is be.ing treated as an NCV consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the violation was identified by the licensee and was not willful, actions taken as a result of a previous violation should not have corrected this problem, and appropriate corrective actions were completed by the licensee (50-458/97008-07).
The licensee performed an analysis to determine the root cause(s) of the above problems and came to the conclusion that there was no process in place to prevent fire watch tours I
from being missed before they occur. Corrective actions taken by the licensee to address j
this root cause were:
j Fire watch tours were added to the Security Shift Report and Radio Log (SECFM 111). The Secondary Alarm Station will be notified and will document the start and completion of each fire watch tour, each hour.
Fire watch personnel were equipped with radios for calling in start and stop times of tours.
The Security Department issued a bulletin to reinforce expectations on the above
=
corrective actions.
The inspectors noted that the above corrective actions addressed the specific causes and will probably ensure that people being relied upon to perform specific hourly fire watch tours will be aware of their assignments; however, the inspectors noted that the corrective actions (or existing processes) did not appear to ensure that fire watch tours were completed in the areas specified on the fire watch route log.
The licensee responded that random key card history checks that have been and will continue to be performed acted as a deterrent against improper or abbreviated tours. This t
coupled with supervisory oversight provided adequate assurance, though after the fact, that tours were being conducted in accordance with the fire watch route log. The inspectors acknowledged the licensee's position.
i 23-l l
c.
Conclusions The licensee's fire protection program was flawed in the area of hourly fire watch implementation in that no process was in place to ensure that the hourly tours were completed as scheduled. A violation was identified by the licensee where, over a 2-month period,105 of 305 tours were nu; anducted by a single individual. An NCV was identified and corrected by the licensee 4 months later, when a different individual failed to conduct a required fire watch tour, as scheduled, for different causes.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the_ inspection results to members of licensee management at the conclusion of the inspection on June 16,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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' ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee J. P. Dimmette, General Manager, Plant Operations 1
M. A. Dietrich, Director, Quality Programs D. T. Dormady, Manager, Plant Engineering J. R. Douet, Manager, Maintenance J. Holmes, Superintendent, Chemistry H. B. Hutchens, Superintendent, Plant Security D. N. Lorfing, Supervisor, Licensing
-J.' R. McGaha, Vice President-Operations
' W. P. O'Malley,- Manager, Operations D. L. Pace, Director, Design Engineering A. D. Wells, Superintendent, Radiation Control INSPECTION PROCEDURES (IP) USED I
. IP 37551 Onsite Engineering IP 61726 Survei!!ance Observations IF 62707 Maintenance Observation
]
1 IP_71707 Plant Operations IP 71750 Plant Support Activities
'lP 92700 '
Onsite Followup of L'ritten Reports of Nonroutine Events at Power Reactor j
Facilities -
j IP 93702 Prompt Onsite Response to Events at Operating Power Reactors IP 92902 Followup - Maintenance i
ITEMS OPENED AND CLOSED Opened 50-458/97008-02 IFl Root cause of failed FCV vent valve weld (Section M1.2) 50-458/97008-05 VIO Failure to properly classify and declare a NOUE (Section P4.1) 50-458/97008-06 VIO Failure to perform fire watch tours (Section F1.1) i i
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l.
4' 5
2-l l
l Closed 50-458/96015-04 IFl Review of MOV thrust settings to cope with expected differential pressure (Section M8.1) i 1
-l Opened and Closed -
50-458/97008-01 NCV Failure to follow procedures requiring TS [CO entry (Section 01.2) 50-458/97008-03 NCV Failure to properly implement three clearances (Section M4.1) 50-458/97008-04 NCV Incorrect damper position for SGTS surveillance (Section E1.1) 50-458/97008-07 NCV Failure to perform a single firewatch tour (Section C1.1) 1 i
4-
-7 4
i
.J J
UST OF ACRONYMS USED
'ALARA as low as reasonably achievable CR
. Condition Report EDG emergency diesel generator EOOS-equipment out of service EPA electrical protection assembly FCV flow control valve
-gpm.
gallons per minute -
IFl' inspection followup item IP inspection procedure kV' kilovolts
-LCO limiting condition for operation LPCI' low pressure coolant injection MAI Maintenance Action item MOV motor-operated valve 1
i MSIV -
. main steam isolation valve l
NCV noncited violation
'NOUE Notification Of Unusual Event PDR Public Document Room RHR residual heat removal RPS reactor protection system SEA safety and engineering analysis SERT Significant Event Response Team SGTS standby gas treatment system SS Shift Superintendent STA Shift Technical Advisor TS Technical Specification i
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U.S. NUCLEAR RE2UL47@QY COMMISSION myosCE Nuuata INVOICE
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""* 9 U.S. NUCLEAR REGULATORY COMMISSION WVotet 0471 DIVISION OF ACCOUNTING AND FINANCE OFFICE OF THE CONTROLLER September 9, 1997 l
WASHINGTON. DC 21588 UCENSE NUM884 &espesseel
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.i AIFlagste NUMeem trase6catel PECO Nuclear s
P. O. Box 2300' CowtACT Sanatoga, PA-19464-0920 f
TELEPMoNa AREA NuMafR Coot 301 e
ollemiPTioN AMoVNT l
Received full payment for EAs97-050 and 97-115, dated August 5, i
1997, Docket Nos. 50-352 aND 50-353.
$80,000 i
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AMOUNT DUE rs= r - >
$80,000 TEIMS.~ interest will accrue from the invc. ice date at the annual rete of.
is received within 30 days from the invoice date. Penalty and administrative charges will b ditions are attached. if applicable.
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if there are any questens about the existence or amount of the debt, contact the individual named cwdmg interest and penetty provisions, see 31 U.S.C. 3717,4 CFR 101-105, and 10 CPR 15.
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CHECK NUMBER 673292
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ENDOR NUMBER AMOUNT -
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PAY Eighty thousand and 00/100 Dollars
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PECO NUCLEAR recocees<comaaev PO Box 2300 A LNr or PECO (s!m 19464-0920 naga Fax 610 718 3008 Pager 1800 672 2285 #8320 10 CFR 2.201 September 4,1997 Docket Nos. 50-352 50-353 License Nos. NPF-39 NPF-85 Director, Office of Enforcement U.S. Nuclear Regulatory Commission Attn.: Document Control Desk Washington, DC 20555
SUBJECT:
Limerick Generating Station, Units 1 and 2 Reply to a Notice of Violation and Payment of Civil Penalty NRC Office of Investigation Report Nos. 1-96-006 and 1-96-033 Enforcement Actions97-050 and 97-115 Attached is PECO Energy Company's reply to a Notice of Violation for Limerick Generating Station (LGS), Units 1 and 2, that was contained in your letter dated August 5,1997. The Notice concerned instances of falsification of information required to be kept by PECO Energy in accordance with the requirements of 10CFR50.9. The attachment to this letter provides a restatement of the violation followed by our reply. A check in the amount of $80,000 for payment of the civil penalty is enclosed.
i i Although several incidents of record falsification were identified at LGS, a thorough investigation determined that these were independent cases. The incidents were not indicative of a generic concern regarding a willingness to misrepresent activities. Neither were the incidents indicative of the culture at LGS with respect to the integrity of station personnel and their willingness to raise issues of concern. PECO Energy emphasizes employee behaviors that 3
reflect important core values including integrity, openness, trust and respect.
Management continually relies on the integrity and trustworthiness of station htktOl1T
][1 li!Iglyl:Ipigilpl!Ili!Il
Docket Nos. 50-352 and 50-353
' September 4,1997 Page 2 personnel to perform'their assigned duties, and to raise issues of concern. Both cited issues were identified by station employees. The corrective actions were prompt and appropriately comprehensive based on the nature of '5e issues.
Additionally, there were no plant safety consequences stemming from these incidents.
PECO Energy is committed to ensure that an open culture continues to exist at all of its facilities. As a result, a letter from the Senior Vice President of Nuclear Operations will be issued to all PECO Nuclear personnel reemphasizing that the company's standard for Operational Excellence is based on each individual living to the core values described above, in addition, this letter will reemphasize that no one is expected to compromise their values for any reason, and that anyone who believes their values may be compromised should raise such a concern to management's attention.
If you have any questions or require additional information, please contact us.
Very truly yours,
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.2 Attachment cc:
H. J. Miller, Administrator, Region I, USNRC w/ attachment N. S. Perry, USNRC Senior Resident inspector, LGS 1
f
Attachment Docket N'os. 50-352 and 50-353 September 4,1997 Page 1 of 5 Reply to a Notice of Violation l
Restatement of the Violation i
As a result of investigations conducted by the NRC Office of Investigations, and PECO Energy company, violations of NRC requirements were identified. In accordance with l
the " General Statement of Policy and Procedure for NRC Enforcement Actions,"
NUREG-1600, the Nuclear Regulatory commission proposes to impose a civil penalty pursuant to Section 234 of the Atomic energy Act of 1954, as amended (Act),42 U.S.C.
2282, and 01 CFR 2.205. the particular violations and associated civil penalty are set forth below:
10 CFR 50.9 requires, in part, that information required by the Commission's regulations or license conditions to be maintained by the licensee shall be compete and accurate in all material respects.
Technical Specification (TS) 6.10.2.d requires, in part, that records of surveillance activities required by TSs be retained for at least 5 years.
1.
Contrary to the above, a record of a TS surveillance activity required to be main'ained by the licensee at Limerick, was not complete and accurate in all material respects. Specifically, on February 7,1996, while a Reactor Enclosure Cooling Water (RECW) radiation monitet was inoperable, the licensee was required, in accordance with TS 3.3.7.1, ACTION 72, to obtain and analyze at least one grab sample from the RECW system at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On that date, the sample needed to be taken by 11:00 a.m. to meet the requirement. Although the sample was not taken until 12:15 p.m. on that date (approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 15 minutes after the time it was due), the record of the RECW Surveillance Test (ST 0926-570-1, "Inop Reactor Enclosure Cooling Water Rad Mon Grab Sampling and Analysis"), signed by a chemistry technician and the chemist (as chemistry supervision), was inaccurate because: (1) page one of attachment 1 of the test record indicated that the time of the sample was 11:00 a.m., and (2) the attached computer printout of the Gamma Spectrum Analysis (required by step 4.3.1 of the surveillance test) also indicated that the sample was taken at 11:00 a.m.. This record was material because it provides evidence as to whether the licensee met l
l the grab sample requirements. (01012)
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f
- Attachment Docket Nos. 50-352 and 50-353 l
September 4,1997
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Page 2 of 5 l
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2.
Contrary to the above, certain surveillance records requirod to be maintained by the licensee at Limerick, were not complete and accurate in -
all material respects. Specifically, on three occasions between April 3, 1995 and June 28,1995, the records for fire protection surveillance tests I
. required by TS 4.7.6.2.c and TS 4.7.6.5.a were not accurate in that certain fire hose and sprinkler system inspections were recorded as having been completed, even though plant security data indicates that the technician was not present in the vicinity of the equipment to perform the inspection. These records were material because they provide evidence as to whether the licensee met the fire protection surveillanca requirements. (01022)
This is a Severity Level 11 problem. (Supplement Vil)
Civil Penalty - 580,000.
REPLY Admission of the Violation i
PECO Energy acknowledges the violations.
Reasons for the Violations The cause of the violations was cognitive personnel error in the first case, a
. Chemistry Technician was aware of the assignment to obtain and analyze the RECW system fluid sample but did not pay sufficient attention to obtain the sample by the set time. The Technician and a former Chemist, at the direction of a former Primary Chemistry Manager, deliberately falsified tne record of the time the grab sample was taken from the RECW system. The Primary Chemistry Manager also pressured the Technician and Chemist to lie about their actions to security personnel investigating the matter. In the second case, a fire protection Technical Assistant deliberately failed to perform fire hose station and sprinkler system visual inspection surveillance tests, yet falsified the surveillance test documents to indicate the tests were performed.
l
Attachment Docket Nos. 50-352 and 50-353 September 4,1997 l
Page 3 of 5 Corrective Actions Taken and Results Achieved Chemistry As indicated in LER 1-96-005, the results of the sample analysis indicated that there was no RECW system contamination, and therefore, there were no plant safety consequences as a result of the late analysis.
Based on the results of the PECO Energy's independent internal investigation, unescorted access was suspended for both the Primary Chemistry Manager and the Chemist on the next working day.
As a result of this incident, the Primary Chemistry Manager and the Chemist were suspended with the intent to terminate, and both subsequently resigned from PECO Energy.
The Chemistry Technician initially identified the late sample, was coerced by the Primary Chemistry Manager to falsify and provide a fabricated account of the events, and subsequently revealed the true facts concerning the event. As a result, the Technician was counseled and the individual's security access was reinstated.
Subsequent to the start of the independent internal investigation, the Limerick Vice President convened a task force of five individuals from outside the Limerick organization to determine the overall integrity of the Chemistry function at Limerick.
The results of the task force indicated that PECO Energy Core Values, such as integrity, openness, trust and respect, were important to chemistry persnnnel. In addition, the results indicated that Chemistry personnel were not reluctant to raise nuclear safety issues.
Fire Protection After admission of intentional falsification, the individual's unescorted access was suspended, and the individual was appropriately disciplined, including suspension of employment.
The applicable surveillance test (ST) procedures were re-performed. The ST procedures were all completed satisfactorily indicating that the affected Fire Protection equipment was operable. Therefore, there were no plant safety consequences as a result of the failure to perform the inspections.
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Docket Nos. 50-352 and 50-353 September 4,1997 Page 4 of 5 Management expectations regarding personal integrity were reinforced to all members of the Fire Protection Group.
Corrective Actions to Avoid Future Noncompliance Chemistry
'I A Chemistry all-hands meeting was conducted to discuss the event as well as management's expectations on completeness and accuracy of information required by the NRC.
Expectations on personal integrity were reinforced with Chemistry Supervision.
A Read and Sign on personal integrity was issued to Chemistry personnel.
The site Directors were briefed on the issue.
The opportunities for Chemistry organization improvements identified by the Chemistry Task Force were addressed.
Fire Protection Based on the findings within the Fire Protection Group, management expectations for personal integrity were reinforced to all members of the Site Support Division.
In addition, because of both the Chemistry and Fire Protection issues, the Limerick Vice President issued a letter to all site personnel regarding personal integrity.
Site-wide Actions Because of both the Chemistry and the Fire Protection incidents, the independent investigation was expanded to include other onsite groups. Some discrepancies were identified, were further investigated, and were addressed by line management. These discrepancies were considered to be associated with poor work practices. Based on the results of the assessment, management concluded there was no generic concern regarding falsification of records.
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Docket Nos. 50-352 and 50-353 September 4,1997 Page 5 of 5 in a'ddition, group meetings were held with all site personnel. At these meetings, the Vice President and other senior managers discussed the expectations of truthfulness and integrity.
' Nuclear Group Actions A letter from the Senior Vice President of Nuclear Operations will be issued to all PECO Nuclear personnel reemphasizing that the company's standard for Operational Excellence is based on each individual living to such core values as integrity, accountability, openness, trust, and respect. In addition, this letter will reemphasize that no one is expected to compromise their values for any reason, and that anyone who believes their values may be compromised should raise such a concern to management's attention.
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Date When Full Compliance was Achieved
' With respect to the Chemistry event, full compliance was achieved on February 7, 1996, when the Unit 1 RECW fluid sample was obtained and analyzed, and determined l
not to be contaminated. With respect to the Fire Protection events, full comp;iance was
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' achieved by August 27,1996, when all of the applicable inspections had been performed and the fire protection equipment was found to be operable.
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