IR 05000445/1993001
| ML20127K412 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/22/1993 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20127K403 | List: |
| References | |
| 50-445-93-01, 50-445-93-1, 50-446-93-01, 50-446-93-1, NUDOCS 9301260118 | |
| Download: ML20127K412 (18) | |
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APPDiDIX U.S. NUCLEAR REGULATORY COMMISSION MGION IV inspection Report: 50-445/93-01 50-446/93-01 Operating License: NPF-87 Construction Permit: CPPR-127 Licensee: 1U Electric Skyway Tower 400 North Olive Street, L.B. 81 Dallas, Texas 75201 facility Name: Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 Inspection At: CPSES, Glen Rose, Somervell County, Texas inspection Conducted: January 4-8, 1993 Inspectors: P. C. Wagner, Team Leader, Division of Reactor Safety L. E. E11ershaw, Reactor Inspector, Maintenance Section Division of Reactor Safety Approved: j /' 22-O Dwig W 0. Chamberlain Deputy Diret. tor Date Division of Reactor Eafety inspection Summary Areas Inspected (Unit 11: A routine, announced inspection of the licensee's self-assessment and corrective action programs was conducted during the period of January 4-8, 199 Areas Inspected (Unit 2): No Unit 2 inspection activities were conducte Results (Unit 1),:
- The licensee's self-assessment program was generally found to be strong, with quality assurance and the onsite review committees functioning as intended (paragraph 2.2).
- A weakness was identified with respect to the Independent Safety Engineering Group's procedures being silent regarding requirements and responsibilities for action, followup, verificatio:,, and 9301260118 930122 PDR ADDCK 0500044S G PDR
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possible management escalation associated with recommendations and responses (paragraph 2.2.3).
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- The inspectors noted an unusually high occurrence of both personnel errors and problems related to temporary modifications in the listing of ;
Plant Incident Reports. However, the licensee had implemented actions to address both of those areas. The licensee had established a Personnel Error Task Team and was responding to temporary modification problem In addition, the resident inspectors were closely following the temporary modification issues. Thereforn, these issues were not included in this inspection (paragraph 3.2).
- The inspectors noted the existence of some issues which appeared to be long-lived. Recent procedure revisions should, however, resolve this concern (paragraph 3.2.2).
- The inspectors considered the use of multiple, independent reviews to be a strength of the. licensee's corrective action program (paragraph 3.2.7). ,
- The licensee's corrective actions in response to all of the conditions ,
that were reviewed by the inspectors were adequate and most were comprehensively handled (paragraph 3.3).
Results (Unit 21: Not Applicable Summary of Inspection findinas:
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- Inspection followup Item 445/9045-01 - Installation of Incorrect Relay -
was closed in paragraph * The following Licensee Event Reports-were closed in paragraph 5:
90-25 90-31 ,
90-35 90-36 92-01 92-04 92-07
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92-14 92-15 92-16 9?.-17 92-18 92-19:
92-21 l
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Attachments: >
- Attachment 1 - Personnel Contacted and Exit-Meeting ,
- Attachment 2 - Documents Reviewed 5
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DETAILS 1 PLANT STATUS During this inspection period, Comanche Peak Steam Electric Station (CPSES)
Unit I was operating at power and Unit 2 was in the startup-testing phas No inspection activities were conducted on Unit EVALUATION OF LICENSEE SELF-ASSESSMENT CAPABILITY (40500) Backaround The inspectors performed an evaluation of the effectiveness of the licensee's self-assessment program The inspection was conducted to determine whether the licensee's programs contributed to the prevention of problems by monitoring and evaluating plant performance, providing assessments of problems, and communicating and following up on corrective action recommendation .2 Discussion The inspectors reviewed Technical Specifications (TS) 6.2 and 6.5, and the-applicable procedures listed in Attachment 2 to determine the functions and- ,
responsibilities of organizations designated to perform self-assessment activitie . Operations Review Committee The Operations Review Committee (0RC) activities were controlled by Revision 20 to the Operations Review Committee manual dated November 18, 1991.-
The manual implemented the requirements of TS 6.5, which recuired the ORC to provide independent reviews and audits. The ORC was chargec with the responsibility for review and verification'of: actions associated with-unreviewed safety questions; changes to TS; violations having nuclear safety significance; significant operating abnormalities that affect nucicar safety; all reportable events; all unanticipated deficiencies that could affect nuclear safety, and the reports and meeting minutes of the Station Operations-Review Committee (50RC). Audits, encompassing a wide range of activities, were to be performed under the cognizance of the ORC within specified frequencie The inspectors reviewed the minutes of the six' ORC meetings (identified in Attachment 2) held during 1992,.in order to_ verify that the above requirements were being implemented. The meetings, which lasted for up to two days, were documented in great detail and clearly c:stablished that the ORC was cognizant of.all unit activities and that they were discharging their responsibilities in an appropriate manne _
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The inspectors also reviewed two quality assurance (QA) audits that had been performed under the cognizance of the ORC: Quality Assurance audits QAA-92-129. " Document and Record Control Program" and QAA-92-131, " Control of
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Materials, Parts, and Components." The audits were thorough and identified several deficiencies and observations, all of which had been, or were in the process of being responded to, in addition, the inspectors also reviewed a riport dated April 14, 1992, which was titled " Annual Assessment of the Overall Effectiveness of the QA Program for 1991." This annual assessment was required by Nuclear Engineering and Operations Policy Statement Number 117, .
" Quality Assurance," and Procedure STA-ll3, " Senior Management QA Overview Program." The assessment was an exceptionally comprehensive evaluation of TV Electric's QA program. Further, the assessment followed up on areas that had been identified for consideration / improvement / action in the 1990 annual assessment. The assessment summarized the conclusions by statire that the implementation of the TV Electric QA program was very effective, in annual Joint Utility Management Audit (JUMA) was performed during February 24-28, 1992, in which an assessment of the QA audit program was performed. The JUMA was conducted by three personnel, each from QA management positions at three different licensees. The JUMA identified 11 observations, each of which was responded to in a positive manner. The conclusions of the JUMA were summarized by stating that the audit results were satisfactory and that the-TV Electric QA staff exhibited an overall positive attitude and sense of .
dedication,
, 2. Station Operations Review Committee lhe inspectors reviewed the activities of the 50RC to ascertain if TS requirements for composition, duties, meeting frequency, and responsibilities were being met. Procedure STA-401 delineated and-implemented the TS requirements. The 50RC typically reviewed such items as Plant incident Reports, independent Safety Engineering Group reports, plant modification requests, and open action items. In addition, the_SORC reviewed procedure revisions, safety significance evaluations, and other conditions which might -
require licensing action. The SORC also reviewed plant events and often assigned action items to committee member The 50RC appeared to use an adequate-tracking system to maintain accountability of those action-item The SORC met at least monthly and as necessary to approve-or discuss additional-issues that occurred. The inspector attended the SORC meeting-conducted on Wednesday, January 6, 1992, at 2 p.m. Duriag this meeting, 50RC reviewed and approved the minutes of the preceding meeting, reviewed and/or approved procedures,_and discussed single failure criteria. The inspectors-also reviewed minutes of six SORC meetings conducted during 1992, in order to verify that SORC's responsibilities were being implemented. Further, the _
inspectors' reviewed the_ training records of the 22 designated SORC members and alternates with respect to the performance of 10 CFR Part 50.59 reviews. With the exception of two individuals, all personnel had received the required training as evidenced by' review of actual attendance sheets. The two individuals were new appointees to the SORC (October 9 and November -10,--1992),
and were within the-procedurally allowed 90 day limit for required trainin _ . _- . . _____u . _ ;, . _ _ - - -- __
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-6-Based on the above reviews and obse, tions, the inspectors concluded that the 50RC was properly performing its intended functio . Independent Safety Engineering Group The requirements applicable to the Independent Safety Engineering Group (ISEG)
were specified in TS 6.2.3, and administrative 1y controlled in Procedure NQA 1.20. The ISEG is responsible for performing independent assessments of plant operations, engineering, maintenance, technically related activities, and surveillance of Unit I activities. The ISEG consists of two units:
assessments and surveillanc?s. The responsibilities for ISEG assessments were addressed in Procedure NQA 1.21 while those for ISEG surveillances were in NQA 3.23. Specific instructions for the performance and documentation of ISEG assessments and surveillances were provided in "lSEG Assessment Desk Top Reference" and Revision 1 to "lSEG field Notes Desktop Instruction,"
respectively. It was noted that reports generated as a result of surveillance activities were titled " field Note Reports."
The inspectors reviewed records and noted that the ISEG engineering personnel met the minimum, procedurally established, education and experience requirements (a Bachelor's degree in engineering or related science and at least 3 years of engineering experience). The inspectors reviewed assessment and surveillance schedules, the status of ISEG recommendations resulting from those activities, and several assessment and surveillance reports, in general, the reports indicated that an in-depth review of the subject matter had been performed. The inspectors requested an updated report showing the status of open recommendations. The report, "Open ISEG Recommendations,"
dated January 7, 1993, showed that there was one assessment report with three recommendations and five field note reports with 11 recommendations open. The assessment report was just a little over 2 months old and the response due dates were slightly overdue; however, actions had been initiated regarding the response. The field note reports ranged in age from 3 months to 7 months old and the requested responses to the associated recommendations were overdue from just days to slightly over 3 months. There was nothing documented to show that any dialogue had been established between ISEG and the affected organization in terms of either extending the due dates or initiating a response. The inspectors discussed two of the oldest field notes (FN-92-15S and FN-92-178 dated June 10 and June 30, 1992, respectively) with the two assigned ISEG individuals. Each indicated that there had not been any contact by the affected organization nor had there been any followup by them to try to ascertain the response status. They indicated that this was routine practic The inspectors reviewed the applicable procedures and determined that there were no requirements for the affected organization to respond to ISEG recommendations, there were no followup activities required of ISEG personnel in terms of monitoring the status of responses, there were no verification activities required after having received a response, and there was no defined mechanism for elevating issues to the appropriate levels of management if recommendations and subsequent responses could not be resolve The inspectors were informed that all levels of management were apprised of ISEG activities and status of reports / recommendations through the issuance of a
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-7-monthly activity summary report. The inspectors noted that monthly status reports were issued; however, they were not considered to be an effective method for achieving resolutions to recommendations. The monthly status report provided a sunnary of reports / recommendations and applicable response closures. ISEG Assessment Report IAR 92-05, " Environmental Equipment Qualification Assessment," dated November 5, 1992, contained eight reccomendations. The recommendations were responded to by Plant Engineering in an office memorandum dated November 24, 1992. Review of the assessment / recommendations, responses, and the synopsis presented in the monthly status report indicated that certain of the responses were accepted and closed without a defined basis. The inspector discussed these concerns _
with the appropriate personne .3 Conclusions In general, the inspectors found that the licensee's self-assessment activities were being conducted in a manner that was conducive to improvement of programs and performanc The ORC, 50RC, and Nuclear Overview Department appeared to be functioning at a level intended to promote self-improvemen The activities of the self-assessment groups, with the exception of ISEG's recommendation / response actions, appeared to be well defined, performance oriented, and were being implemented. The reviewed records indicated that personnel were well qualified for the activities that were being performe With the exception of the identified weakness in the ISEG program, the inspectors considered the self-assessment program to be a strengt CORRECTIVE ACTION (92720) Background
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The inspectors conducted a performance based evaluation of the licensee's corrective action progra The objective of the inspection was to determine if the licensee had implemented a comprehensive program to correct safety-related problems and preclude their reoccurrenc .2 Discussion Tne inspectors reviewed the licensee's listing of problem reports and noted an unusually high occurrence of both personnel errors and problems related to temporary modifications in the listing of Plant incident Report However, the licensee had implemented actions to address both of those areas. The licensee had established a Personnel Error Task Team and was responding to temporary modification problems. In addition, the resident inspectors were closely following the temporary modification issue Therefore, these-issues were not included in this inspectio The inspectors selected 16 events for detailed review from the listing of 83 events that had been documented in 1992 as significant problems. Significant events or problems were classified as Plant Incident Reports (PIRs) on the licensee Operations Notification and Evaluation (ONE) Form Of the 16
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-8-reports that were reviewed, the inspectors had comments on the following 10 PIRs:
3. ONF form FX 92-048: Main Generator Coolina Water The main generator tripped on January 8, 1992 because of high cooling water temperatur his caused a turbine trip and a reactor tri The events related to this issue were reported in Licensee Event Report (LER) 92-0 The licensee determined that this issue was a sigrificant problem and designated it a Plant incident in accordance with P ocedure STA-422, -
" Processing of Operations Notification and Evaluation (ONE) forms." In addition, an evaluation team was established in accordance with Procedure STA-423, " Evaluation Teams." The evaluation team was chartered to " evaluate the overall congruity of the technical information available to operate the turbine generator set . . ..
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The evaluation team made seven recommendations for corrective actio The PIR evaluated a number of areas and presented 16 recommer.dations which included the 7 recommendations from the evaluation team. The inspectors found the evaluation and recommendations to be thorough and complete. The inspectors verified that action notifications (ANs) were issued for all of the recommendations in accordance with Procedure STA-42 The inspectors also verified that the corrective actions described in LER 92-01 had been incorporated in the AN . ONE form FX 92-169: Improper Readings During Surveillance Test This ONE form was initiated because the battery terminal voltage was recorded while the battery was receiving an equalizing charge. The TS require the -
reading to be taken during float charge conditions. This cc.idition was described in LER 92-0 '
lhe licensee determined that the craft personnel had misinterpreted the requirements and that the testing procedure did not contain clear instructions. The licensee counselled the involved personnel and implemented procedure enhancement The inspectors found the licensee's corrective actions to be appropriate for the proble .2.3 ONE Form FX 92-224: Temporary Su_pports Not Installed On february 22, 1992, Valve 2HV-4515 was removed from the piping system for maintenanc The work authorization for this Unit 2 activity required the installation of temporary supports because of the possible impact on the stress analysis for the Unit 1 Component Cooling Water System. The temporary supports were not, however, installed when the valve was removed. The licensee, therefore, initiated this PIR to evaluate the integrity of the Unit 1 pipin _ __ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _
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-9-The inspectors reviewed the licensee's operability assessment and corrective actions and found them to be comprehensive. However, the inspectors noted that this problem had occurred more than 10 months ago and remained open, in addition, the location of documentation was not readily apparent. The licensee explained that timeliness issues had been identified during Quality Assurance Audit QAA-92-121 and had been addressed by revisions to STA-42 The documentation management system had been changed during 1992 to a new system (PR-ISM) that had not been completely updated for issues in proces The inspectors noted that Revision 7 to STA-422 became effective on October 30, 1992, and required completion of the evaluation of plant incidents _
within 30 days and completion of corrective actions within 90 day . ONE form FX 92-316: Failure to Perform Surveillance Within Limits This PIR documented that the TS surveillance requirements had not been satisfied on April 1, 1992. The Train B Emergency Diesei Generator was taken out of service for maintenance. The availability of the offsite power supplies was, therefore, required to be verified within one hour and every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafte The initial verification was performed within one hour, but the reverification was not completed for over 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> thereafter. The offsite power remained available throughout the maintenance period. This event was described in LER 92-0 The licensee implemented changes to the method of tracking surveillance requirements to preclude a reoccurrence of this type of event. The changes included establishing a shift briefing requirement for all special conditions and a standardized method of tracking time limitations. The licensee also -
installed two " marker-boards" with integral timers in the control room. The timers alarm to alert the operators that action will be needed. The inspectors found the licensee's actions to be proactiv .2.5 ONE form FX 92-508: Blackout Seguencer Time Delay Setting
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The setpoint for the time delay of the undervoltage relay associated with the blackout sequencer was to have been changed from 0.5 seconds to 0.4 seconds as part of Design Modification 90-105. The blackout sequencer was provided to reconnect safety-related loads onto the 6,9kV bus when reencrgized by the alternate source of offsite powe The failure to implement this setpoint change was discovered during the recent comparison of differences between Unit I and Unit 2. The event was described in detail in LER 92-1 The licensee evaluated the condition and determined that the incorrect setpoint would only result in a problem when no large motors were running on the 6.9kV busses. When a large motor was connected to the bus, sufficient voltage would be provided back to the bus by the residual voltage of the motor. The licensee did not identify any operating history with no large motors being energize . - - - - _____
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-10-The licensee implemented the setpoint change to the time delay relay. The licensee reviewed similar design modifications and no additional problems were identified, in addition, changes to the design modification process were revised to track completion of approved change .2.6 ONE Form FX 92-514 and 700: Trip of Both liain feedwater Pumps These PIRs described reactor trips that were caused by the trip of both nain feedwater pumps. The first trip occurred on June 11, 1992, and was determined to have been caused by t; s spurious actuation of the nonsafety-related anti-waterhammer circuitry. The licensee was unable to identify any malfunction of the circuitry and returned it to service. The second trip occurred on Jaly 20, 1992, and was determined to have also resulted from spurious actuation of the anti-waterhammer circuitry. These event:, were discussed in LERs 92-14 and 92-1 The licensee's immediate corrective actions appeared reasonable and conservative. The anti-waterhammer circuitry was temporarily bypassed with the concurrence of the reactor vendor uritil a sufficient outage to allow more in-depth troubleshooting than allowsole curing reactor operatio The inspectors also noted that the licensee's Plant Analysis Group haj recently (Memo CPSES 9240194 dated December 31, 1992) requested additional evaluations to resolve concerns related to the two events. The inspectors considered this type of review to be indicative of a properly functioning corrective action progra . ONE form FX 92-571: toose Connection Disables Turbine Trips A loose wire inside the main turbine control cabinet disabled two of the Train A turbine trip functions. The problem was originally identified on May 16, 1992, but was considered to only affect the Automatic Turbine Tester circuitry because manual testing proceeded as expecte During troubleshooting on June 11, 1992, the loose wire was identified and repaired. The licensee's corrective actions also included a procedure revision to require periodic verification of connections inside the cabine The System Engineer evaluated the effects of the loose connection on September 11, 1992, during a closeout review of the PIR. The System Engineer determined that the loose connection would have disabled two of the turbine trip functions from the Train A devices (reactor trip and high steam generator level trip). The licensee determined that all Train B trip devices and all other Train A devices remained operable throughout the even The implications of loss of the trip functions were reported in LER 92-2 The inspectors considered the use of multiple, independent reviews to be a strength of the licensee's corrective action program, h...m -.
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3.2.8 ONC form FX 92-589: Automatic Transfer of Safety-Related Busses A severe storm on June 23, 1992, caused the failure of a switchyard transmission line support and resulted in a flashover. The fault was cleared b/ the switchyard circuit breakers which, in turn, caused a momentary loss of ,
power to the preferred startup power source (Transformer XST2). The safeguards busses automatically transferred to the alternate source of offsite power (Transformer XSTI) but the blackout-sequencer was actuated. A11 equipment operated as designed. The licensee implemented repairs and modifications to the line supports to improve their capabilities and reliabilit This event was described.in detail in LER 92-1 The licensee submitted the LER because the blackout sequencer operated causing the actuation of some safeguards equi) ment. The inspectors reviewed the corrective actions and found them to )e acceptable. The inspectors also reviewed the SORC comments from a meeting held on July 22, 1992, and determined that the event had been evaluated as required by the corrective action progra ,
The inspectors also determined that the actuation of the blackout sequencer '
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was not affected by the time delay relay setpoint problem discussed in ONE form ft 92-508, discussed abov .2.9 ONE form FX 92-590: Valve Stroke-Time Not Proper 1v Tested This PIR discussed the stroke time testing for two motor operated valve The two valves (lHV-2452-1 and -2) were being stroke-time tested in the open direction but not in the closed direction. The valves were designated as containment isolation valves and, therefore, were required to be stroke time tested in the closed direction. However, the valves fail to the-open direction and perform their safety function by opening to admit steam-to the turbine driven auxiliary feedwater. pum Upon discovery of the discrepancy, the licensee immediately tested the valves with satisfactory results. The- 1 licensee also reviewed similar surveillance requirements and did not identify-any other discrepancies. The licensee revised the valve testing listing to ensure proper testing in the future. This event was discussed in LER 92-1 The inspectors found the-licensee's corrective actions to be reasonable and-complet .2.10 ONE Form FX 92-672: Accident Analysis Computations The licensee determined that the small break loss of coolant accident calculation resultad in fuel cladding temperatures that exceeded the acceptance criteria of 2200*F contained in 10 CFR'Part 50.46. The calculation utilized the_ older computer program (WFLASH) that was referenced in the safety-analysis report and the Technical Specifications but incorporated refinements to the input parameters.- The licensee also calculated the temperatures-utilizing the newer computer program (NOTRUMP) with the refined input parameters. The use of NOTRUMP was approved by the NRC in 1985. The results
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-12-from the N01 RUMP calculation were well within the acceptance criteri The details of this problem were described in LER 92-1 T ht. ii ansee submitted license Amendment Request TXX-92323 dated September 3, 1992, to revise the analysis method of record from WFLASil to NOTRUMP. The acceptance of the licensee's request was being tracked by an Action Notification in accordance with program requirement i i
3.3 Conclusions The inspectors found the reviewed issues to have been properly evaluated and ;
corrected in accordance with the corrective action program. The inspectors l found all of the reviewed issues to have been adequately handled and most of the issues were handled in a comprehensive manne The inspectors noted an unusually high occurrence of both personnel errors and problems related to temporary modifications in the listing of Plant incident Reports. However, the licensee had implemented actions to address both of those areas. The licensee had established a Personnel Error Task Team and was responding to temporary modification problems. In addition, the resident inspectors were closely following the temporary modification issue The inspectors noted the existence of some issues which appeared to be.long-lived. Recent procedure revisions should, however, resolve this concer The inspectors considered the use of multiple, independent reviews to be a strength of the licensee's corrective action progra FOLLOWUP (92701)
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(Closed) Inspection followup item 44519045-01: Installation of Incorrect Relav in Emergency Diesel Generator (FDG) Control Cabinet The licensee replaced a relay in the Train B EDG voltage regulating circuitry I on December 13, 199 The relay was replaced as a preventive maintenance activity to eliminate minor relay chattering that was occurring during EDG startu The replacement relay, however, failed during post-maintenance testing. The initial licensee evaluation determined that~the replacement relay was not properly rated. The licensee, therefore, initiated ONE Form FX 90-2554 to determine how the improperly rated relay had been installe During this inspection, the licensee's ONE form and supporting documants were reviewed. The replacement relay (Deltrol Controls Style 166) had been certified as a qualified and interchangeable replacement for the originally installed relay (potter and Brumfield KUP-14A15) by the EDG vendor (Certificate of Compliance dated October 2, 1989). The two relays were similar in construction and nominal ratings, but the pickup and dropout voltages were somewhat different. The higher pickup and lower dropout voltages of the replacement relay caused severe relay chattering during the EDG startup and led to relay failure. The licensee remov:d the failed relay
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and installed an original type rela The EDG was then tested and returned to servic he inspectors verified that the licensee had performed a receipt inspection and acceptance tests for the certified replacement relays. The testing was ,
performed to verify that specified minimum pickup voltage and the insulation resistance were satisfied. The inspectors also noted that the licensee submitted a 10 CFR Part 21 notification to the NRC by letter TXX-91088 dated february 75. 199 ,
in addition, the licensee implemented Design Modification 90-168 to replace the original relays with direct current relays to eliminate the relay chattering problem that occurred during EDG startup. The nodification was completed on the Unit 1 EDGs on June 17, 1991, and on the Unit 2 EDGs on January 21, 199 ONSITE FOLLOWUP 0F WRITTEN REPORTS OF NONROUTINE EVENTS (92700)
The inspectors reviewed the following Unit 1 Licensee Event Reports (LERs) as part of the corrective action program evaluatio , (Closed) lER 90-25: Main Feedwater System Flow Control Valve The licensee reported that_ the flow control for feedwater to steam generator -
No. 2 failed to the open position while the unit was operating _at near full power on August 25, 1990. The operators were unable to close the valve from the control room and high steam generator level led to a turbine trip and reactor trip. The licensee found the feedback linkage arm from the valve stem to the positioner disconnected. The bolt mechanism had apparently " backed-out" due to vibrations caused by flow-induced oscillations. The linkage-arm was reattached using a lock washer. The licensee also initiated a design change to modify the valve internals to reduce flow induced oscillation The flow control valve failed to the full open position again on September 7, 1990. The licensee discovered the feedback linkage sheared and reported the event in LER 90-27. The licensee again repaired the valve and proceeded with the valve _ modification evaluation. The licensee actions in response to the second event were found acceptable in NRC Inspection Report 50-445/91-28; 50-446/91-28 and LER 90-27 was close During this inspection, the completion of the . licensee's corrective actions were verifie .2 _
(Closed) LER-90-31:
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Failure to Compl.y with Action Statement The licensee reported that.the Containment Gaseous Radioactivity Monitoring System was declared inoperable on July- 23, 1990. The Containment Air Cooler condensate flow rate alarm setpoints were determined to be r.on-conservative on August 10, 199 With these concurrent conditions, the licensee entered the Action Statement for Technical Specification Limiting Condition for
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-14-Operation 3.4.5.1, and began taking containment atmosphere sample The licensee nbrequently determined that the flow rate setpoints had been non-conservat h e since February 8, 1990. Therefore, the containment' sampling should have commenced immediately when the monitoring system became inoperable. (This problem was discussed in NRC Inspection Report 50-445/90-40; 50-446/90-40.)
The licensee determined that the root cause of the event was the use of non-conservative assumptions in calculating the flow rate setpoints. The licensee recalculated and implemented the revised setpoints. The licensee also provided guidance on the calculation methodology to ensure proper implementation of both design and operational activitie .3 (Closed) LER 90-35: Potential Common Mode Failure of High Safety injection (HPSI) Pumps The licensee reported that the solenoid operated valves in the suction piping for the HPSI pumps would not isolate flow in the reverse direction. The valves would prevent flow from the HPSI pumps' suction from being diverted to the volume control tank, but might not prevent flow from the tank to the HPSI pumps' suction. This condition could lead to gas binding of all HPSI pumps and was determir,ed to have been caused by less than adequate review of design requirements. (This problem was also discussed in NRC Inspection Report 50-445/90-40; 50-446/90-40.)
The licensee's corrective actions included immediately closing the manual isolation valves and verifying that similar installations were capable of isolating flow in both directions. The licensee also revised engineering procedures to include consideration of appropriate design inputs. The valves in question were replaced during the 1992 refueling outag _ (Closed) LER 90-36: Failure to Comply with Technical Specifications On October 23, 1990, one of the two Train B Primary Plant Ventilation Systems was determined to be inanerable be:ause of a temperature switch problem. The condition had been found on October 15, 1990, and repairs had not been completed. The plant was operating d the condition was not recognized at a TS issue until monthly surveillance testing was required. The lictnsee stated that both Train A systems and the other Train B system remcined operable through the even The licensee submitted Revision 1 of the LER on February 14, 1991. The root s causes of the event were determined to be the failure to take appropriate action when the problem was first discnvered and the lack of an unambiguous alarm syste The inspectors verified that the licensee had modified the alarm circuitry to remove inputs from nonsafety-related components and had revised the alarm response procedur _ _ - - - -______ - _______ _ __ _ _____ _ _-_-__ _ _ _ _ - _ - ___-
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-15-5.5 (Closedj LFRs The followin9 LERs were reviewed as part of the licensee's corrective action program evaluation. The licensee's investigation and resolution of the e' ~.s were found to be acceptable and the LERs are close . 92-01, see ONE Form FX 92-048 e 92-04, see ONE form FX 92-169 e 92-07, see ONE form FX 92-316
. 92-14, see ONE Form FX 92-514
- 92-15, see ONE Form FX 92-508 ~
- 92-16, see ONE Form FX 92-589
- 92-17, see ONE form FX 92-590 e 92-18, see ONE Form FX 92-672
- 92-19, see ONE Form FX 92-700
- 92-21, see ONE Form FX 92-571
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ATTACHMENT 1 1 PERSONS CONTACTED Licensee Personnel
- 0. Bhatty, Site Licensing-Engineer
- Blevins, Director of Nuclear Overview
- Bradley, Radiation, Protection Supervisor
- Bruner, Senior Vice President
- Curtis, Radiation Protection Supervisor
- Davis, Manager, Plant Analysis
- Flores, Shift Operations Manager
- W. Guldemond, Manager, ISEG
- D Kay, Radiation Protection Supervisor
- J. Kelley, Vice President, Nuclear Operations
- D. McAfee, Manager, Quality Assurance
- J. McMahon, Manager, Nuclear Licensing
- G. Merka, Licensing Engineer
- S. Palmer, Stipulation Manager
- J. Patton, Quality Specialist
- R. Prince, Radiation Protection Manager
- D. Reimer, Manager, System Engineering
- S. Smith, Work Completion Control Manager
- Stendebach, Senior Engineer
- L. Strope, Quality Specialist
- S. Swam, Technical Training Supervisor
- W. Taylor, Staff Assistant
- C. Terry, Vice President, Nuclear Engineering and Support-
- R. Walker, Manager of Regulatory Af fairs 1.2 NRC Personnel
- Jones, Senior Resident Inspector
- R. Latta, Resident Inspector
- L. Ricketson, Radiation Specialist
- Denotes. personnel that attended the exit meeting. In addition to the personnel ' listed above, the inspectors contacted other personnel during this inspection perio EXIT MEETING
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An exit meeting was conducted on January 8, 199 During this. meeting, the-L inspectors reviewed the scope and findings of the inspection. The licensee l did not identify as proprietary any information provided to, or reviewed by, l the inspectors.
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ATTACHMENT 2 DOCUMEn(S REVIEWED Procedures:
Number Title Revision ALM-Oll3 Alarm Response Procedure X-ALB-llc 3 MSE-SI-5000 Station Batteries Weekly Surveillance 0&1 STA-206 Review of Vendor Documents and Vendor 17 Technical Manuals STA-401 Station Operations Review Committee 17 STA-421 Operations Notification and Evaluation (ONE) Forms 3 STA-422 Processing ONE Forms 7 STA-423 Evaluation Teams 2 STA-707 10 CFR 50.59 Reviews 9 NQA-1.20 Independent Safety En9 neering i Group Member Qualifications and Responsibilities 1 NQA-1.21 ISEG Assessments and Reports 0 NQA-2.ll Trend System 3 NQA-3,23 Surveillance Program 6 owl-203 Operations Department Management Periodic Reviews 6 ISEG Surveillance Desktop Instruction- 1 ISEG Shutdown Risk Assessment Guidelines 0 Operations Notification and Evaluation (ONE) Forms:
FX 92-048 FX 92-169 FX 92-224 FX 92-316 FX 92-334 FX 92-380 FX 92-392 FX 92-425 FX 92-508 FX 92-514
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! -2-FX 92-571 FX 92-589 FX 92-590 FX P2-672 FX 92-700 FX 92-847 O
J erations Review Committee Meeting Minutes 92-01 through 92-05 and 92-05A
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Quality Assurance Audits and Assessments QAA-92-129 Document and Record Control Program 0AA-92-131 Control of Materials, Parts, and Components Annual Assessment of the Overall Effectiveness of the Quality Assurance Program for 1991 JUMA 92-01 Annual Joint Utility Management Audit (JUMA) Assessment of the Quality Assurance Audit Programs Station Operations Review Committee Meeting Minutes92-099 92-108 92-118 ISEG Assessment Reports and Field Notes
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IAR 92-01 1AR 92-04 IAR 92-05 IAR 92-14 FN- 92-155 FN- 92-178 ISEC Monthly Activity Summary Reports
March 1992 October 1992 No*: ember 1992
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