IR 05000461/1998018
| ML20198H987 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 12/17/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198H974 | List: |
| References | |
| 50-461-98-18, NUDOCS 9812300066 | |
| Download: ML20198H987 (29) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION lli Docket No:
50-461.
License No:
NPF-62 Report No:
50-461/98018 (DRP)
Licensee:
lilinois Power Company Facility:
Clinton Power Station Location:
Route 54 West Clinton, IL 61727 Dates:
October 2 - November 17,1998 Inspectors:
T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector C. E. Brown, Resident inspector D. E. Zemel, Illinois Department of Nuclear Safety Approved by:
Thomas J. Kozak, Chief Reactor Projects Branch 4 9812300066 981217 PDR ADOCK 05000461 G
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EXECUTIVE SUMMARY
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Clinton Power Station NRC Inspection Report 50-461/98018 (DRP)
This inspection included aspects of licensee operations, engineering, maintenar.ce, and plant support. The report covers a 7-week period of resident inspection.
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Operations
~ The licensee conducted effective post event assessments for a loss of Division i
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load tap changer, and movement of a radwaste liner. The assessments were timely and identified the causes associated with the events (Sections 01.1, E1.1, and R1.1).
The inspectors identified one violation, for which enforcement discretion was exercised,
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for the failure to conduct a hazards analysis as part of the safety evaluation for a temporary modification used to support Division i emergency core cooling system (ECCS) testing. Specifically, the safety evaluation did not address the possible effects
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of temporarily installed cables routed in the vicinity of safety-related equipment that was not being tested as part of the ECCS testing activities (Section O1.2).
The new operations department shift turnover process, implemented in August 1998,
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was an improvement from the previous method used for turnovers in that personnel used clear communications, operators asked clarifying questions, and the full operations crew participated in the briefing (Section 01.3).
The inspectors and the licensee identified multiple examples of ineffective corrective
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action program implementation for level 3 and 4 condition reports. Specific issues involved ineffective management oversight, poor apparent cause analysis, inadequate extent of condition determinations, and ineffective corrective actions for identified apparent causes (Section 07.1).
The inspectors identified one violation, for which enforcement discretion was exercised,
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which involved the failure to adhere to procedures that limit unit staff working hours.
Specifically, one chemistry technician worked in excess of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period, one control and instrumentation technician worked more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day period, and operations personnel failed to conduct a monthly review of overtime use for
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June 1998. Though a violation was identified, recent efforts to improve management oversight of the program have been successfulin limiting staff working hours (Section 08.3).
Maintenance The inspectors concluded that inadequate preparations for measuring the lifting torque
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on high pressure core spray (HPCS) inlet check valve 1E22-F005 resulted in the loss of
as-found data during the measurement. The failure of the non-licensed operator to attend the mechanical maintenance department pre-job briefing may have contributed to this event. No instructions were included in the work package as to what type of
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adapter was needed for the measurement and the workers failed to note the problems with the adapter in the remarks section of the surveillance procedure (Section M1.2).
Quality assurance personnel conducted a thorough, critical evaluation of the licensee's
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maintenance rule program (Section M7.1).
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Enaineerina i
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One non-cited violation was identified due to the licensee's identification that
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j engineering personnel had failed to fully understand the operational characteristics of the emergency reserve auxiliary transformer load tap changer prior to testing on October 22,1998 (Section E1.1).
The inspectors determined that the local leak rate testing program was well controlled,
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that engineering personnel were knowledgeable of local leak rate testing requirements,
and that adequate actions had been taken to implement Option B of Appendix J to 10 CFR Part 50 (Section E1.2).
i The inspectors determined that engineering personnel actively conducted critical
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self-assessments in an effort to identify departmental strengths, weaknesses, and opportunities for improvement. In addition, weaknesses and recommendations were adequately tracked to ensure resolution (Section E7.1).
Plant Succort The licensee's assessment of the stuck fire shield in a shipping cask was effective in
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that the licensee, based on this assessment, determined that the event was caused by poor resolution of previously identified concerns and non-conservative decision making which resulted in a radwaste liner and fire shield becoming lodged in a shipping cask (Section R1.1).
Licensee controllers and evaluators in both the technical support center and the i
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operations support center provided an accurate assessment of activities during the October 14,1998, emergency drill. The licensee's observations and post drill critiques for the technical support center and operations support center were effective in recognizing strengths, weaknesses, and areas for continued improvement (Section P1.1).
Licensee controllers and evaluators in the sim~ lator main control room did not provide a u
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critical assessment of activities during the October 14,1998, emergency drill.
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Specifically, licensee personnel did not identify two failures to properly implement emergency operating procedures, the lack of a questioning attitude regarding inaccurate information and equipment operation by operations personnel, that a delay of approximately 25 minutes had occurred in declaring a Site Area Emergency, and poor communications between emergency facilities involving reactor core isolation cooling injection valve operation and prioritization of activities (Section P1.1).
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Reoort Details Summary of Plant Status l
The facility remained shutdown during the inspection period. Major maintenance and testing i
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activities that were completed included: a Division I outage, ECCS testing, and testing of the emergency reserve auxiliary transformer (ERAT) automatic load tap changer (LTC)
I modification. The ERAT LTC modification was implemented to improve the reliability of the 138 kVac offsite power source relative to voltage supplied to the plant.
I. Operations
Conduct of Operations
01.1 Loss of Division i Electrical Bus
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Insoection Scope (71707)
The inspectors reviewed actions taken by operators in response to a loss of the Division I electrical bus on October 18,1998.
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_ Observations and Findinas The licensee determined that power to the Division i electrical bus was lost due to a
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tagging error. Specifically, operations personnel that were instructed to clear a tagout on the reserve auxiliary transformer (RAT) potential transformer cubicle proceeded in
error to the Division I electrical bus potential transformer cubicle. As the operators opened the cubicle door for the Division I bus potential transformer, the potential
l transformer fuses were removed from the circuitry due to a safety interlock. As a result, the reserve feed breaker to the Division I bus opened, power was lost to all Division i equipment, and the emergency diesel generator (EDG) started in response to an undervoltage signal. Control room operators entered the loss of shutdown cooling and i
loss of power off normal procedures in response to the event and restored the residual
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heat removal (RHR) mode of shutdown cooling within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
The licensee conducted a critique of the loss of the Division I electrical bus event and determined that inattention-to-detail and inadequate supervisory oversight contributed to the tagging error. Specifically, operations personnel that cleared the safety tagout failed to use proper self and peer checking techniques to ensure that they had identified the correct potential transformer cubicle prior to opening the cubicle door. In addition, the field supervisor did not observe the operators' performance even though this was a first time evolution for the operators clearing the tagout.
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As discussed in NRC Inspection Report 50-461/98017, licensee management has taken several actions to improve overall performance in the tagout program. Notwithstanding this event, these actions have generally been effective in improving overall performance in this area. To address this event, the licensee planned to provide just-in-time training
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.to operations personnel, revise the safety tagging procedure to provide additional
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- guidance, and communicate expectations for close management oversight of tagout work, especially during first tir.e evolutions.
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Conclusions
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l A thorough, probing critique of the loss of power to the Division I electrical bus and
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resultant loss of shutdown cooling was conducted following the event. The causes of
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the event were determined to be inattention-to-detail by the operators clearing the
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tagout and the failure to have the expected supervisoy oversight for a first time
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01.2 - Division i Emeroency Core Coolina System (ECCS) Intearated TestiO2
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Insoection Scooe (71707)
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The inspectors observed control room activities during the ECCS ir:tegrated testing o
evolutions.
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Observations and F4.33
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On' September 30,1998, the licensee was in the process of conc'ucting Division I
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' integrated testing of the ECCS in accordance with Procedure 9030.21, " Diesel l
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Generator 1 A - ECCS Integrated." A temporary modification was used to perform the test. The inspectors observed numerous test cables that were temporarily routed across the control room floor and installed in panels through open doors that did not -
have a positive, mechanical stop to prevent pinching of the cables. The same observation was made during Division ll Integrated testing and was documented in
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inspection Report 50-461/98014. The inspectors informed the shift manager of the i
condition who realized that this was not a good practice and took immediate adions to
remove the panel doors where the test cables were installed.
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The inspectors reviewed the safety evaluation which was completed for the temporary modification as required by Procedure 1005.06, " Conduct of Safety Reviews,"
Revision 8. Step 8.3.4.1 of Procedure 1005.06 stated, in part, that safety evaluations conducted for plant modifications shall consider critical elements associated with work activities such as equipment qualification and hazards analysis. The inspectors identified that the safety evaluation for the temporary modification did not address the j
possible hazards associated with the routing of the temporary test cables in the vicinity of safety-related equipment in the control room that was not being tested. The f:dlure to
- perform a hazards analysis as part of the safety evaluation conducted for the temporary modification for the Division I integrated ECCS test was a violation of Procedure 1005.06. -This procedure is required to be implemented by Technical Specification (TS) 5.4.1.a. However, because this v!Jlation satisfies the criteria in L
Section Vli.B.2, " Violations identified During Extended Shutdowns or Work Stoppages,"
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of the " General Statement of Policy and Procedures for flRC Enforcement Actions" (Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued for this Severity Level IV violation (NCV 50-461/98018-01).
l In response to this issue, operations personnel stopped the test until a new safety L
ev&luation had been completed. The inspectors reviewed the new safety evaluation and noted that it addressed the possible hazards associated with the installation and routing l
of the temporary test cables.
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Qgnclusion The inspectors identified one violation, for which enforcement discretion was exercised, for the failure to conduct a hazards analysis as part of the safety evaluation for a temporary modification used to support Division i ECCS testing. Specifically, the safety evaluation did not address the possible effects of temporarily installed cables routed in the vicinity of safety-related equipment that was not being tested as part of the emergency core cooling system testing activities (Section 01.2).
01.3 Shift Turnover Observation (71707)
The inspectors observed control room turnover activities during the mornings of October 18 and November 1,1998. Clear communications were used by all members of the operating crew and an improved questioning attitude was demonstrated when the operators asked several clarifying questions regarding system status. The inspectors noted that the new turnover pro 2ss, implemented in August 1998, had also enhanced crew communications in that it raquired full participation by all members of the operations crew. The inspectors considered the new turnover process to be an improvement over past turnover methods which limited the participation of crew members.
Quality Assuran::6 In Operations 07.1 R.eview of Condition Reports (CRs) Closed by the Operations Deoartment a.
Inspection Scope (71707)
The inspectors reviewed 11 completed level 3 CRs, closed during September 1998, in order to assess the effectiveness of operations personnelin determining the apparent cause, developing corrective actions, and determining the extent of the condition for the issues documented in the CRs. Of the CRs reviewed, six were initiated after implementation of Procedure 1016.01, " CPS Condition Reports," Revision 31, dated May 11,1998.
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Observations and Findinas Condition Reports initiated Prior to implenientation of Procedure 1016.01, Revision 31 Based on their review of five operations department CRs, initiated prior to Revision 31 to Procedure 1016.01, the inspectors identified one CR with an ineffective extent of condition review, one CR with narrowly focused corrective actions, one CR with a poorly documented analysis, and two CRs that were considered acceptable. Specific examples of the CRs which needed additional work included:
Condition Report 1-98-01-131 was initiated on January 15,1998 after the
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containment building ventilation fan was operated with the discharge damper closed. Operations personnel determined that the apparent cause of this event was that the power supply to the discharge damper was not included in the bus outage checklist. The inspectors determined that operations personnel did not perform an adequate extent of condition review as no assessment was made of whether other bus outage checklists for the containment building ventilation
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system were similarly affected nor did they assess whether on nct a generic problem existed with bus outage checklists provided in plant procedures. On October 23,1998, following discussions with the inspectors, operations personnel determined that other bus outage checklists for containment building ventilation were not similarly affected.
Condition Report 1-98-02-298, initiated on February 17,1998, involved the
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overload of the Division ll EDG. Operations personnel determined that the root cause for the event was an instrument failure of the optical isolator card.
Corrective actions involved shipping the optical isolator card and power supply to a vendor for failure analysis. The inspectors noted that no corrective action item was assigned to review and assess the results of the vendor failure analysis. On November 5,1998, operations personnel informed the inspectors that the analysis had not been completed by the vendor and that a review of the analysis results would be conducted as part of CR 1-98-02-215.
An additional corrective action involved a revision to the non-licensed operator (NLO) log sheets to include local readings for generator parameters. This item was developed due to the NLO not being aware of the need to monitor important equipment parameters associated with EDG operation. It was determined that the training for local EDG operation did not include instructions to locally monitor EDG load. This training was revised and operators were retrained on this activity. The inspectors noted that an assessment to determine whether or not additional log sheets should be revised to include local readings which provided an indicatior Weeptable operation of other safety-related components was not conducted. i.. 5,*mber 3,1998, following discussions with the inspectors, operations person..el stated that the operating crews would be contacted to determine if additionalitems needed to be added to NLO log sheets.
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Condition Report 1-98-03-071, initiated on March 5,1998, involved a spurious
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trip of the containment purge system fan. Operations personnel concluded that the cause of the trip could not be determined, but they did not document the supporting analysis. Following discussions with the individual assigned to evaluate the issues documented in the CR, the inspectors concluded that an adequate review had been conducted but was not documented. Operations personnel supplemented CR 1-08-03-071 with additional information regarding the analysis.
Condition Reports initiated Following implementation of Procedure 1016.01, Revision 31 Based on their review of six operations department CRs, initiated following implementation of Revision 31 to Procedure 1016.01, the inspectors identified three CRs with poor apparent cause analyses resulting in incomplete corrective actions, two l
CRs with ineffective extent of condition reviews, and one CR that was considered acceptable. Specific examples of CRs which needed additional work included:
Condition Report'1-98-06-262, initiated on June 22,1998, involved locked valve
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deficiencies. Operations personnel attributed the apparent cause to human error resulting in valves not being properly locked. The inspectors determined that deficie@ies noted in CR 1-98-06-262 were resolved; however, an assessment of the extent of the condition was not conducted. On October 23,1998, following discussion with the inspectors, operations personnel conducted a trend analysis and concluded that a potential adverse trend did not exist with controlling locked valves.
Condition Report 1-98-07-137, initiated on July 11,1998, involved the failure of
high pressure core spray (HPCS) check valve 1E22-F024 to close. Operations personnel, without the assistance of the system engineer, did not determine an apparent cause for valve 1E22-F024 failing to reseat. Instead, the apparent cause analysis stated that this was not a condition adverse to quality and that the check valve operated properly when retested under Procedure 9051.01, "HPCS System Pump Operability." On October 23,1998, following discussions with the inspectors, operations personnel questioned the system engineer as to why the
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valve initially failed to reseat. The system engineer determined that maintenance on the HPCS system had required manually opening valve 1E22-F024 in order to drain the system. During the system restoration, the licensee had failed to manually close valve 1E22-F024. Operations personnel stated that CR 1-98-07-137 would be amended to include the additionalinformation and a revised apparent cause.
Condition Report 1-98-07-233, initiated July 18,1998, involved a missed
surveillance test due to operations personnel annotating "N/A" on the control room operator surveillance log for source range monitor channel checks.
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Operations personnel determined that the apparent cause was due to an
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an individual marking 'NA' on the log sheet." The inspectors determined that the
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assessment of CR 1-98-07-233 did not include a review to determine why peer and supervisory reviews of the control room operator surveillance log did not result in the missed surveillance test being identified. Operations personnel agreed with the inspectors' observations.
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Condition Report :-98-07-329, initiated on July 27,1998, involved the failure of
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the NLO to conduct watchstanding duties due to being assigned to the Division 11 EDG area duri'a testing. Operations personnel determined that the watchstanding c,fies were not completed due to inadequate shift resources.
The inspectors concluded that the CR 1-98-07-329 assassment did not include a review to determine wny there were insufficient shift resources, if resources had been inappropriately assigned, or the extent of supervisory oversight by the control room supervisor and shift manager. On November 6,1998, operations personnel reopened CR 1-98-07-329 to reassess the apparent cause.
Condition Report 198-08-260, initiated on August 21,1998, involved a failure of
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the self-test system (STS). The apparent cause analysis specified that the CR was initiated for trending purposes only as required by Procedure 3513.01,
"NSPS [ Nuclear System Protection System]- Self Test System (STS)."
Operations personnel conducted an extent of condition search of the CR database and identified 22 additional CRs involving the STS which were initiated between February 1996 to August 21,1998. The trend report was fonvarded to the system engineer in a memorandum which specified that the information was provided for the system engineer's use in tracking and trending hardware
conditions associated with the STS. The inspectors noted that a determination as to the significance of the trend data was not conducted and that no corrective actions were initiated as a result of the trend information.
On October 17,1998, following discussions with the inspectors, operations personnel determined that engineering personnel had not initiated actions in response to the information only memorandum. Consequently, operations personnel initiated CR 1-98-10-230 to do:ument a potential trend of STS failures.
Licensee Review of Additional Condition Reports On October 2,1998, the independent analysis group completed a review of three closed operations department CRs. The licensee determined that the CRs contained insufficient information to support conclusions and the extent of the condition review was less than adequate.
On October 5,1998, quality assurance (QA) personnel completed audit Q38-98-19 which assessed the implementation of the' corrective action program and whether management ownership and involvement in the corrective action program was effective.
Quality assurance personnel determined that there was a lack of management commitment to the corrective action program and that corrective actions for identified
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apparent cause analyses were not effective. Following audit Q38-98-19, the licensee formed a root cause team comprised of senior management personnel to address the audit findings.
Collectively, the deficiencies identified by the inspectors and licensee were representative of continuing weaknesses in the licensse's efforts to implement changes to the corrective action program. Improvements in the corrective action program will continue to be evaluated as part of the inspection activities associated with the NRC Manual Chapter 0350, Case Specific Checklist item 111.1, " Establish and Implement Actions to Achieve and Sustain improvement in the Corrective Action Program."
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Conclusions The inspectors and the licensee independently identified multiple examples of ineffective corrective action program implementation for level 3 and 4 condition reports. Specific l
issues involved ineffective management oversight, poor apparent cause ana'ysis, inadequate extent of condition determinations, and ineffective corrective actions for identified apparent causes.
Miscellaneous Operations issues (92700 and 92901)
08.1 (Closed) Licensee Event Report 50-461/97-033: Misinterpretation of TS bases results in failure to meet required TS actions for two inoperable emergency core cooling subsystems. This event was discussed in NRC Inspection Report 50-461/97025 and a Notice of Violation was issued due to the licensee's failure to implement actions required i
by TS. The inspectors reviewed the licensee's corrective actions taken in response to the Notice and documented the results in NRC Inspection Report 50-461/98017. No new issues were revealed by the licensee event report.
08.2 (Closed) Inspection Follow-uo item 50-461/97999-02: Low pressure core spray (LPCS)
alarm set point above relief valve set point. In August 1997, the licensee identified that the set points for the LPCS pump discharge pressure abnormal alarm and the RHR A pump discharge pressure abnormal alarm located in the main control room were higher than the relief valve set points for the associated systems. Specifically, the LPCS alarm annunciated when system pressure reached 580 psig while the relief valve lifted at 554 psig and the RHR alarm annunciated at 480 psig while the relief valve lifted at 477 psig. This condition was undesirable since operations personnel would potentially be unaware of high system pressures prior to relief valve actuation.
The licensee initiated CR 1-97-08-270 to document the discrepancies between the alarm and relief valve set points and conducted an operability determination (OD). The NRC's Special Evaluation Team (SET) reviewed the OD and determined that it was inadequate since it focused on the Operability of the RHR and LPCS systems rather than on the Operability of the main control room alarms. In addition, the SET questioneo why a safety screening was not completed for the non-functioning alarms.
In response to this issue, the licensee revised the OD and determined that the RHR abnormal discharge pressure alarm was operable when the differences in component
i elevations were considereo. nswever, the LPCS abnormal discharge pressure alarm remained inoperable. Operations personnel also conducted a safety screening and determined that the discrepancies between the RHR and LPCS alarm and relief valve set points did not constitute an unreviewed safety question. The inspectors reviewed i
the safety screening and had no concerns.
l The licensee implemented an engineering change notice to lower the set point of the LPCS abnormal discharge pressure alarm such that operations personnel would receive the alarm prior to the relief valve actuating. The inspectors reviewed the change notice and did not identify any additional concerns. No other discrepancies were identified during a subsequent review of other abnormal discharge pressure alarms and relief valve set points. Additional training to improve the conduct of ODs, safety screenings, and evaluations was provided as part of the Plan for Excellence. The inspectors
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considered the licensee's actions adequate.
08.3 (Closed) Inspection Follow-up Item 50-461/97999-18 and Un esolved item 50-461/98002-04: Excessive use of overtime. This issue was initially identified during the SET review. In April 1998, the licensee revised Procedure 1001.10, " Control of Working Hours, and informed perscnnel of manegement expectations regarding the use of overtime. The inspectors reviewed overtime records for operations, engineering, control and instrumentation (C&l), radiation protection, and chemistry personnel, for the month of June 1998, to determine the effectiveness of changes in the control of overtime. In general, improvements had been made in the control of working hours.
Nevertheless, the inspectors identified three examples of poor implementation of working hour limitations.
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I Technical Specification 5.2.2.e, requires that procedures be developed and implemented to limit working hours of unit staff who conduct safety-related functions.
Section 8.1 of Procedure 1001.10 specified, in part, that an individual should not be permitted to work more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period, excluding shift turnover time. Section 8.7 of Procedure 1001.10 specified that all site departments shall submit a monthly report of overtime deviations.
The inspectors reviewed C&l overtime records for the month of June 1998 and noted that one person had exceeded 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day period without receiving prior authorization. The inspectors reviewed chemistry overtime records for the month of June 1998 and noted that one person had exceeded 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period without receiving prior authorization. On August 18,1998, the inspectors noted that operations personnel had not conducted an assessment of overtime usage for June 1998. The inspectors determined that the failure of two individuals to adhere to working hour limitations and the failure of operations personnel to provide a monthly report regarding overtime usage for June 1998 was a violation of TS 5.2.2.e. However, because this violation satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued for this Severity Level IV violation (NCV 50-461/98018-02).
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08.4 (Closed) Insoection Follow-Vo item 50-461/97999-21: This issue involved the integrated safety assessment team (ISA) and special evaluation team (SET)
observations that indications and controls on the remote shutdown panel (RSP) were not as described in the Updated Safety Analysis Report (USAR). A review of the USAR, and discussions with licensee personnel, revealed that the USAR accurately described the indications and controls at the RSP. The USAR specified that certain controls and indications were at the RSP. The ISA and SET interpreted this to mean the indications and controls were on the RSP. The licensee interpreted this to mean the controls were on or in the immediate vicinity of the RSP. The licensee revised Procedure 4003.01,
" Remote Shutdown (RS)," on December 18,1997, to clarify the location of the controls and indications at or near the remote shutdown panel. In addition, the licensee has initiated several USAR changes to fully explain the location of equipment used for l
remote shutdowns. This item is closed.
II. Maintenance M1 Conduct of Maintenance i
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M1.1 General Comments (61726 and 62707)
Portions of the following maintenance and surveillance activities were observed or reviewed by the inspectors:
Procedure 2800.93 Emergency Reserve Auxiliary Transformer Integrated Test Procedure 8221.01 CRD Hydraulic Cont ol Unit Maintenance Procedure 9051.02 HPCS Valve Opert aility Test Procedure 9861.02D077 LLRT Data Sheet (or 1MC210 - Post Accident Sample System AR F02492 Remove and Install Check Valve Air Actuator on valve 1E22-F005 per Section 8.3 of Procedure 9051.02, Section 8.3 MWR D86232 Replace Accumulator,04-33 Hydraulic Control Unit The inspectors noted that observed activities were conducted with the procedure present and in active use. Technicians were knowledgeable of the assigned task and used calibrated test equipment. Specific inspector observations of maintenance activities are discussed in Section M1.2.
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M1.2 Hiah Pressure Core Sorav iniection Testable Check Valve a.-
Inspection Scooe (62707 and 61726)
The inspectors observed the mechanical maintenance department pre-job briefing for and the work activities associated with the removal of the air operator on HPCS inlet check valve 1E22-F005.
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Observations and Findinas On October 18,1998, the inspectors observed the pre-job briefing of mechanical maintenance (MM) workers by the MM supervisor and found it to be thorough in that it included radiological conditions, tools needed, and expected coordination with operations personnel. The task required the MM workers to disconnect the air operator and use an adapter provided by the NLO to connect a torque wrench to the valve stem so the NLO could measure the torque needed to lift check valve 1E22-F005 off its seat.
The NLO did not attend the MM pre-job briefing.
After the air operator was removed, the adapter selected by the NLO v<ould not tighten onto the check valve shaft due to insufficient threads on the adapter adjustment boli. In an attempt to modify the adapter, washers were added under the adjustment bolt by ihe MM workers at the job site. Nevertheless, the adapter slipped when the check valve disk won first lifted, which resulted in a loss of the as-found torque value. Following the job, the inspectors observed that neither the MM workers nor the NLO noted the problems with the adapter in the remarks section of the surveillance procedure.
c.
Conclusions The inspectors concluded that inadequate preparations for measuring the lifting torque on HPCS inlet check valve 1E22-F005 resulted in the loss of as-found data during the measurement. The failure of the NLO to attend the MM department pre-job briefing may have contributed to this event. No instructions were included in the work package as to what type of adapter was needed and the workers failed to note the problems with the adapter in the remarks section of the surveillance procedure.
M7 Quality Assurance in Maintenance Activities M7.1 Review of Quality Assurance Audit of Maintenance Rule Proaram Between September 21 and October 2,1998, QA personnel conducted audit Q38-98-18 to determine the adequacy and effectiveness of the maintenance rule program. During the audit, QA auditors identified that the maintenance rule program, as written, was adequate; however, program implementation remained ineffective. Specifically, poor attendance at expert panel meetings, poor support in training expert panel members and alternates, and poor support by system engineers had prevented the effective implementation of the maintenance rule program. Quality assurance auditors also identified that, as written, Procedure 1151.12, "On-Line Risk Assessment," limited the licensee's ability to implement an on-line risk assessment process. Specifically, the I
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procedure did not: 1) limit the use of unapproved computer software for performing risk assessments, 2) describe the director-operations responsibilities, 3) provide limitations i
in the use of operatorjudgement, and 4) list the documents generated as a result of
Procedure 1151.12 implementation it was also identified during the audit that the corrective actions developed for four CRs associated with the maintenance rule were ineffective. As a result of the ineffective maintenance rule program implementation, QA j
personnel recommended that an additional audit be conducted before startup to i
evaluate the effectiveness of licensee corrective actions to address the problems identified with the implementation of the maintenance rule program. The inspectors j
concluded that the OA audit was thorough, probing, and accurately assessed the state of the maintenance rule program.
M8 Miscellaneous Maintenance issues (9302)
M8.1 (Closed) Notice of Violation 50461/9'7014-01 A: Failure to refer to electrical diagrams l
during ground isolation activities. On June 24,1997, during ground isolation activities, reactor water cleanup pump suction outboard isolation valve 1G33-F004 shut due to personnel error. Specifically, personnel did not follow a caution statement in Procedure 4201.01C001, " Loss of 125VDC MCC 1 A (1DC13E) Load impact List."
Corrective actions involved training for operations personnel on the importance of identifying the electrical configuration of the plant before manipulating breakers and revising Procedure 4201.01C001. The licensee noted a similar deficiency in Procedure 4201.01.C002, " Loss of 125VDC MCC 1B (1DC14E) Load imps :t List,"
which impacted inboard suction valve 1G33-F001. The inspectors considered the corrective actions adequate.
M8.2 (Closed) Notice of Violation 50-461/97014-02: Failure to use controlled " Official Working" or " Approved for Work" copies of procedures while conducting maintenance.
The licensee conducted training that included discussions with system engineers and maintenance technicians on the use of " Approved for Work" documents at the job site.
Following implementation of the corrective actions, the inspectors have not observed any additional examples of using unapproved documents at job sites. The inspectors considered the corrective actions adequate.
M8.3 (Closed) Notice of Violation 50-461/97014-03: Failure to adequately illuminate the protected area. The licensee determined the root cause for this event to be a program weakness in that no check and balance existed involving the movement of Sea-Land containers to ensure light near the containers remained adequate. The corrective actions included revisions to Procedures 1701.55, " Patrol Procedure," 1701.55F001,
" Security Lighting Map," and 1032.07," Vehicle Access to CPS." The inspectors have not observed any subsequent occurrences of inadequate lighting inside the protected area and consider the corrective actions adequate.
M8.4 (Closed) Notice of Violation 50-461/97022-02: Failure to control copies of vendor manuals. This issue involved the use of uncontrolled measuring and test equipment manuals by operations and maintenance personnel. The licensee removed all uncontrolled vendor manuals from the test equipment checkout area and revised Procedure 1512.01, " Calibration and Control of Measuring and Test Equipment," to add
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requirements to review all new and existing vendor manuals for upgrade to a controlled status, The inspectors considered the corrective actions adequate.
M8.5 (Closed) Notice of Violation 50-461/97022-03: Failure to prepare work documents.
The root cause for the violation was determined to be the use of conditional statements in maintenance work requests (i.e., if required, as necessary, etc.). Corrective actions hcluded: the formation of a maintenance planning process improvement team to evaluate the planning process and identify areas for improvement, training for planners to ostablish guidelines concerning the use of conditional statements such as "as needed" and "as necessary," and revising Procedure 1029.01, * Preparation and Routing of Maintenance Work Documents." The inspectors considered the corrective actions adequate.
M8.6 (Closed) Non-Cited Violation 50-461/98003-07: This is a violation involving the failure to ensure resistance temperature detector (RTD) testing was included as part of a test control program for which enforcement discretion was exercised. In response to this issue, maintenance planning personnelinitiated CR 1-97-12-221 and began a root cause investigation. Based on the results of the investigation, the licensee determined that diesel ventilation system RTDs had not been tested due to the failure to consider USAR testing requirements during the development of preventive maintenance (PM)
tasks. In addition, the licensee determined that RTD testing and channel checks had not been conducted for at leact three other ventilation systems even though this testing was required by the USAR.
In response to this issue, the licensee completed testing on the Division ll ventilation systems via maintenance work requests to maintain the equipment operable for Mode 4.
Comment control forms and PM evaluation requests were also initiated to ensure that PM tasks and procedures were written to support future testing on all three divisions.
The inspectors were informed that the Division il test procedures were in the process of being written and were scheduled to be completed by early 1999, in addition to the corrective actions described above, the licensee conducted a review of other USAR ventilation testing requirements and initiated over 120 new PM evaluation requests. The inspectors considered the licensee's actions adequate to resolve this issue.
M8.7 (Closed) Non-Cited Violation 50-461/98003-08: This is a violation involving the failure to conduct an adequate 10 CFR Part 50.59 safety evaluation screening when changing the testing methodology for the diesel ventilation system for which enforcement discretion was exercised. The licensee reviewed the PM and procedure history for the diesel ventilation system and determined that testing of each ventilation channel was changed from a loop calibration to a controller calibration on November 23,1990. Although a 10 CFR Part 50.59 screening was completed, the screening was inadequate because it failed to note the change in testing methodology as a change to a procedure described in the USAR. In response to this issue, the licensee implemented actions to create PM tasks and procedures to conduct the USAR required testing as discussed in Section M8.6. Additional training on conducting safety screenings was also provided as part of the licensee's Plan for Excellence. The inspectors considered the licensee's actions adequate to resolve this issue.
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- 1 lit, Ennineering E1 Conduct of Engineering
- E1.1 Emeraency Reserve Auxiliary Transformer (ERAT) Automatic Load Tao Chanaer (LTC)Testina
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ac Insoectia Scone (37551. 61726. and 71707)
On October 2. <38, the inspectors observed operations and engineering personnel i'
during the conduct oiEPAT LTC testing.
l b.
Observauons and Findinos The LTC can be operated in the manual or the automatic sequential mode, if a degraded or over voltage condition is sensed for greater than 7 seconds when operating l
in the automatic sequential mode, the raise or lower relay in the LTC circuitry energizes and closes the contacts for the LTC motor which raises or lowers the tap settings. The change in tap settings then corrects tiie voltage supplied to the safety-related buses by maintaining voltage at the LTC controller between the raise setpoint of 4121 Vac and the lower setpoint of 4224 Vac. Each step in the tap setting changes the bus voltage by
- approximately 66 Vac.
I On October 22,1998, the inspectors observed that operations personnel controlled ERAT LTC testing well, used proper communications, and demonstrated a good questioning attitude. Specifically, operations personnel questioned the decision to leave
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the ERAT LTC in the automatic mode of operation prior to engineering and operations I
personnel reviewing the test data. Subsequently, the shift manager revised his previous l
decision to leave the ERAT LTC in automatic and instructed that the LTC be placed in the manual mode until the test results were evaluated. The licensee then determined that the test results were satisfactory and placed the LTC in the automatic sequential mode of operation.
On October 23,1998, operations personnel initiated CR 1-98-10-345 when the LTC began automatically cycling between tap positions 2L and 4L. Due to the inadvertent cycling, operations personnel were unable to maintain bus voltage within specifications.
Subsequently, operations personnel declared the automatic sequential mode of LTC j
operation inoperable and placed the LTC in manual.
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During the initial assessment of the cyclic performance, engineering personnel believed that the ERAT LTC would only initiate the number of tap changes needed to return voltage to within specifications while operating in the automatic sequential mode. After
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further review, engineering personnel discovered that operation of the LTC in the
automatic sequential mode resulted in the circuitry initiating a second tap change
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immediately following the first tap change even though the voltage correction from the first tap change may have been sufficient to raise or lower voltage to an acceptable
level. The cyclic performance occurred because the bus voltage band between the l
raise and lower set points for the LTC controller (103 Vac) was less than the voltage l
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correction from two tap changes (132 Vac). As a result, the LTC circuitry continued to initiate tap changes in an effort to correct the voltage deficiencies.
The operations department questioned engineering personnel to determine why the cyclic performance of the LTC was not experienced during the testing conducted on October 22. Engineering personnel explained that the abnormal operation of the LTC had been experienced, but not questioned, during testing since the final voltage following the two tap changes was within the allowable range of acceptable operation for the ERAT LTC.
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On November 3, engineering and operations personnel conducted troubleshooting on the ERAT LTC and determined that the LTC had operated as designed. In addition, the
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licensee determined that Procedure 2800.93, " Emergency Reserve Auxiliary Transformer Integrated Testing," was inadequate in that the acceptance criteria only verified that the ERAT LTC responded to changes in grid voltage rather than comparing
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the actual response of the LTC to the response necessary to return voltage to within the desired voltage band.
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l Criterion XI of 10 CFR Part 50, Appendix B, " Test Control," requires, in part, that a test program be established to ensure that all testing required to demonstrate that
structures, systems, and components will perform satisfactorily in service is identified
l and performed in accordance with written procedures which incorporate the acceptance limits contained in applicable design documents. The failure to establish a test control
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program which incorporated acceptance criteria to demonstrate that the ERAT LTC
performed satisfactorily in service was a violation of Criterion XI of 10 CFR Part 50, Appendix B. However, this non-repetitive, licensee identified and corrected violation is being treated as a non-cited violation consistent with Section Vll.B.1, of the Enforcement l
Policy (NCV 50-461/98018-03).
At the conclusion of the inspection, the licensee was developing a design change to allow the ERAT LTC to be operated in the automatic non-sequential mode of operation.
Implementation of the design change will allow a 7-second time delay to be inserted
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between each tap change to ensure that the ERAT LTC receives and processes
information regarding the acceptability of bus voltage prior to initiating another tap change.
c.
Conclusions One non-cited violation was identified for the licensee's failure to implement a test l
control program which demonstrated that the ERAT LTC performed satisfactorily in service.
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The licensee's assessment of the automated sequential operation of the ERAT LTC was l
effective in that based on the assessment, the licensee determined that engineering personnel had failed to fully understand the operational characteristics of the ERAT LTC prior to testing on October 22,1998.
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l E1.2 Review of Local Leak Rate Testina ProorarD a.
Inspection Scope (37551 and 61720)
The inspectors reviewed the licensee's local leak rate testing (LLRT) program and associated surveillance procedures and observed LLRT testing to determine if the licensee's program was in compliance with the requirements of Appendix J to 10 CFR Part 50.
b.
Observations and Findinas During refueling outage-6, the licensee implemented performance-based LLRT requirements as delineated in Option B of Appendix J to 10 CFR Part 50. Option B allows licensee's to extend LLRT frequencies if previous test results were acceptable.
The inspectors discussed the implementation of Option B with the engineering j
department's LLRT coordinator and determined that the coordinator was knowledgeable
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of the new requirements. The inspectors also reviewed LLRT procedures and the LLRT surveillance schedule to ensure that the new testing frequencies were incorporated into j
both documents and that the documents were consistent. No inconsistencies were i
identified.
The inspectors reviewed 10 maintenance work packages for containment isolation valves and penetrations to ensure that packages were being routed to the correct engineering personnel and that as-found and as-left testing was conducted when required in each case, the work package was routed to the correct engineer and
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as-found and as-left testing had been conducted when needed.
During a review of several LLRT surveillance procedures, the inspectors noted that many of the procedures had been revised. The LLRT coordinator told the inspectors that a procedure change program had been initiated to ensure that the LLRT procedures met management's expectations for content and format. The inspectors observed one LLRT surveillance test and did not identify any procedure adherence concerns.
c.
Conclusions The inspectors, based on a review of the LLRT program, determined that the program was well controlled, that engineering personnel were knowledgeable of LLRT requirements, and that adequate actions had been taken to implement Opticn B of Appendix J, to 10 CFR Part 50.
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E7 Quality Assurance in Engineering Activities E7.1 Enaineerina Self-Assessment Proaram a.
Inspection Scope (37551 and 4050_0_)
The inspectors reviewed the engineering department's self-assessment program and the self-assessments conducted between July and September 1998.
b.
Observations and Findinas During the third quarter of 1998, engineering personnel completed 25 restart readiness reviews, five formal assessments, and nine informal assessments. The large number of self-assessments completed this period was due to the re-establishment of the engineering assurance group as part of the Plan for Excellence. The inspectors reviewed the five formal self-assessments and found them to be thorough and critical.
Each assessment clearly stated program strengths and weaknesses and identified recommendations for improvement.
The inspectors discussed the tracking of weaknesses and recommendations with the engineering assurance supervisor and were informed that weaknesses which constituted conditions adverse to quality were tracked using the CR process. All other weaknesses or recommendations were tracked using a departmental database. The inspectors reviewed the database and noted that each weakness or recommendation was assigned to a specific individual and given a due date. The inspectors noted that several of the due dates listed in the database had already passed and questioned the supervisor about the incorrect dates. The supervisor informed the inspectors that the engineering department has had difficulty closing items in a timely manner due to the large amount of work required to support restart. However, individuals assigned to the engineering assurance group were working with the respective item owners to develop a reasonable completion date.
c.
Conclusions The inspectors determined that engineering personnel actively conducted critical self-assessments in an effort to identify departmental strengths, weaknesses, and opportunities for improvement in addition, weaknesses and recommendations were adequately tracked to ensure resolution.
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Inspection Follow-uo item 50-461/97999-24: Reasonable assurance does not exist for implementing and maintaining the design basis for the low pressure coolant l
injection (LPCI) mode of RHR. In late 1997, the integrated safety assessment team i
could not determine, with reasonable assurance, that CPS programs and processes had implemented and maintained the design basis of the LPCI mode of RHR. The NRC SET inspection confirmed this finding. The licensee initiated a system design and functional validation (SDFV) project in December 1997, which included the RHR system
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results and conduct additional reviews of the licensee's actions as part of the inspection j
activities associated with the NRC Manual Chapter 0350, Case Specific Checklist
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Item VI.1, " Provide Reasonable Assurance that Safety-Related SSCs (structures, systems and components) Will Perform Their Intended Safety Functions as Described in i
the Design and Licensing Basis."
l E8.2 (Closed) Unresolved item 50-461/98011-07: Evaluate the hazards of transporting
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anhydrous ammonia. This issue involved the inspectors' identification that the licensee had not conducted an analysis of the shipment of 1,000 gallon anhydrous ammonia tanks by local farmers within a 2 mile radius of the facility. In October 1998, the licensee completed an analysis which demonstrated that shipment of the anhydrous ammonia i
tanks near the facility did not constitute a significant hazard. The inspectors noted that the assumptions used in the analysis were conservative and consistent with methodologies described in Regulatory Guide 1.78, " Assumptions for Evaluating the Habitability of Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release." Licensing personnel stated that the USAR would be revised to include the hazards analysis for the shipment of 1,000 gallon anhydrous ammonia tanks. The inspectors considered this issue closed without any enforcement action being warrented.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Movement of Radwaste Liner l
a.
Inspection Scope (71750)
On October 29,1998, radwaste programs and radiation protection personnel were preparing a polypropylene liner, which contained spent resin and was encaced in a fire shield, for shipment. As the liner and fire shleid were placed inside the shipping cask, the fire shield became stuck and was unable to be removed. The inspectors monitored the licensee's response to this event and the actions taken to remove the fire shield from the cask.
b.
Obser_vations and Findinas The licensee determined that poor resolution of previously identified concerns and non-conservative decision making contributed to this event. Specifically, each shipping cask contained a support structure, known as a shoring device, to prevent the liner from moving laterally during shipment. Licensee personnel noticed that the shoring device, contained inside the cask utilized on October 29, differed from the shoring devices used previously and expressed concem that the fire shield could become stuck as it was l
lowered inside the cask. However, the licensee took no action to resolve this concern
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prior to placing the fire shield inside the cask.
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While the licensee was lowering the fire shield into the cask, an individual identified that the fire shield appeared to be encountering resistance. In response to this observation, the cask, fire shield, and shoring device were inspected on two separate occasions.
Each time the individual told the supervisor, who was monitoring the cask lowering activity by camera, that the clearance between the fire shield and the shoring device was small. However, the supervisor allowed the cask lowering to continue, since the activity appeared to be going well, instead of stopping the evolution to fully evaluate the j
individual's concerns. As the fire shield was lowered another 12 inches, the cables between the crane and the fire shield went slack. The licensee subsequently j
determined that the fire shield had become lodged inside the shoring device.
The licensee developed a detailed plan for removing the fire shield which involved using a crane to lift the fire shield. The plan also included contingencies and compensatory
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measures. As radwaste programs and radiation protection personnel attempted to lift the fire shield, the crane tripped due to an overload condition. The fire shield was
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subsequently removed by prying it out with a fulcrum device while simultaneously lifting it with the crane.
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Additional licensee review determined that the an error by the cask vendor contributed to this event. Specifically, the shoring device received with the cask was intended to support a liner instead of a liner encased in a fire shield. The licensee was resolving this deficiency with the vendor at the conclusion of the inspection.
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Conclusions The licensee's assessment of the stuck fire shield in a shipping cask was effective in that the licensee, based on this assessment, determined that the event was caused by poor resolution of previously identified concerns and non-conservative decision making which resulted in a radwaste liner and fire shield becoming lodged M a shipping cask.
P1 Conduct of EP Activities P1.1 Emeraency Drill Observations a.
Insoection Scoce (71750)
On October 14,1998, the inspectors observed a site wide emergency drill from the simulator main control room (SMCR), technical support center (TSC), and operations support center (OSC).
b.
Observations and Findinas For the emergency drill, initial plant conditions were 100 percent power with maintenance activities affecting Division I electrical power, LPCS, RHR train A, and reactor water cleanup train B. The scenario started with a contaminated, injured person medical emergency. Following the medical emergency, a reactor coolant leak of greater
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j than 50 gpm developed resulting in the declaration of an Alert. A fire in the Division IV
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battery room resulted in damage to the reserve auxiliary transformer relay panel causing
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a loss of electrical power to Division 11 switchgear and the declaration of a Site Area
Emergency. The reactor core isolation cooling (RCIC) pump tripped upon startup and
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HPCS flow was lost due to a loss of Division lli 480 Vac power which caused a rapid decrease in reactor vessel level. The loss of reactor vessel level and ECCS resulted in a core melt situation and the declaration of a General Emergency. The emergency drill was terminated following the restoration of ECCS and reactor vessel level.
Simulator Main Control Room Observations by licensee controllers and evaluators in the SMCR included: a reactor operator not being observant of parameters and indications for 5 - 6 minutes, poor
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transfer of command authority from the interim station emergency director (SED) to the SED in the TSC, poor oversight of SMCR activities by the shift manager / interim SED, ineffective communications due to multiple personnel being simultaneously involved in phone communications, information regarding the status of the fire not being
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communicated to the SMCR from the fire brigade, and poor diagnostic and system knowledge of the RCIC system.
Positive observations by licensee controllers and evaluators in the SMCR included:
good emergency operating procedure (EOP) usage, effective teamwork and 3-way l
communications, and operations personnel concern for personnel safety. The inspectors concurred with the licensee's assessment of teamwork,3-way communications, and concerns for personnel safety.
The inspectors had the following observations in the SMCR which were not noted by licensee evaluators and controllers; operations personnel did not question conflicting information regarding the contamination levels associated with the contaminated injured person; the shift manager was unaware that the scram had been reset; operations personnel failed to start the hydrogen - oxygen monitors as required by EOP 6, " Primary
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Containment Control;" operations personnel failed to enter EOP 9, " Radioactivity Release Control," when the entry conditions of an offsite liquid or gaseous release rate exceeding the emergency plan alert level were met; approximately 25 minutes elapsed
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between identification of a fire affecting safety-related components and the declaration of the Site Area Emergency; operations personnel responsible for pressure control initiated actions to open safety relief valves without an understanding of the desired pressure band directed by the control room supervisor; an order from the SMCR to open the breaker for the RCIC injection valve was incorrectly communicated such that an OSC field team was dispatched to verify proper operation of the RCIC injection valve; operations personnel unintentionally sprayed containment upon restoration of LPCI due to poor knowledge of containment spray system operation; and inconsistent prioritization of activities existed between the SMCR, TSC, OSC, and emergency operating facility.
Technical Support Center Observations by licensee controllers and evaluators in the TSC included: confusion regarding the transfer of command authority between the SMCR and the TSC, poor
3-way communications, ineffective updates on the status of the fire, poor communications between the TSC and OSC, and the accountability and evacuation
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announcement did not occur until 20 minutes after declaring the Site Area Emergency.
The inspectors' observations were consistent with the licensee's observations.
Positive observations by licensee controllers and evaluators in the TSC included:
announcements and briefings by the SED occurred and information was appropriately
posted on status boards. In addition, the inspectors noted that the declaration of the
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General Emergency by the SED was timely.
Operations Support Center
Observations by licensee controllers and evaluators in the OSC included excessive delays in establishing and dispatching field teams for repair activities and poor 3-way communications existed. The inspectors observations were consistent with the licensee's observations.
The inspectors noted two examples of ineffective direction and oversight of field teams.
In the first instance, a field team was dispatched to bypass the HPCS injection valve.
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The OSC believed the team was dispatched to connect a temporary hose to the upstream and downstream vent and drain valves The repair team thought they were dispatched to conduct a " hot tap" of the upstream and downstream piping. In the second instance, field team 1 notified the OSC that work was completed on RHR Pump A at 10:45 a.m However, at 11:30 a.m., the OSC questioned field team 1 to determine if the work had been completed.
l Positive observations by licensee controllers and evaluators in the OSC involved the response to the contaminated injured person. The inspectors observations were consistent with the licensee's observations.
Controllers and Evaluators The TSC and OSC controllers and evaluators recorded detailed field observations of activities as the emergency drill progressed. The field observations aided in the conduct of an effective post-drill critique and in developing recommendations for continued improvement.
The SMCR controllers and evaluators recorded cursory field observations of activities as j
the emergency drill progressed. Due to the discrepancy between the NRC inspectors'
observations and those of the licensee, the inspectors determined that the controllers and evaluators did not provide a sufficiently critical assessment of the conduct of operations personnel assigned to the SMCR.
Corrective Actions initiated by the Licensee Following the drill, the licensee developed a plan to conduct several training sessions for emergency response organization staff, controllers, and evaluators prior to the
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integrated graded exercise on November 18,1998.
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Conclusions Licensee controllers and evaluators in both the technical support center and the operations support center provided an accurate assessment of activities during the October 14,1998, emergency drill. The licensee's observations and post-drill critiques for the technical support center and operations support center were effective in l
recognizing strengths, weaknesses, and areas for continued improvement.
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l Licensee controllers and e aluators in the simulator main control room did not provide a critical assessment of activities during the October 14,1998, emergency drill.
l Specifically, licensee personnel did not identify two failures to properly implement emergency operating procedures, the lack of a questioning attitude regarding inaccurate information and equipment operation by operations personnel, that a delay of approximately 25 minutes had occurred in declaring a Site Area Emergency, and poor communications between emergency facilities involving reactor core isolation cooling l
I injection valve operation and prioritization of activities.
l P8 Miscellaneous EP issues
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P8.1 (Closed) Insoection Follow-up Item 50-461/97022-04: Training on use of additional operator resources during event response. This issue involved the failure of the SMCR crew to implement EOPs due to a lack of licensed operator resources even though additional operations personnel were available in the OSC. Corrective actions involved remedial training for the affected crew and the development and implementation of requalification cycle training on obtaining additional operations resources. The inspectors considered the corrective actions for this issue adequate.
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 November 17,1998. 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.
X3 Management Meeting Summary i
On October 23,1998, a meeting was held on-site to discuss the status of licensee restart activities and improvement initiatives as well as NRC activities associated with implementation of Manual Chapter 0350," Staff Guidelines for Restart Approval." Specific topics included licensed operator requalification training, safety tagging, the control of calculations and set points, and the resolution of previously identified qualified materials and parts issues.
On November 10,1998, a meeting was held on-site to discuss the status of licensee restart activities and improvement initiatives as well as NRC activities associated with implementation of Manual Chapter 0350," Staff Guidelines for Restart Approval." Specific topics included
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maintenan 4 and engineering support training, the corrective action program, and the status of t-implementing an effective maintenance rule program.-
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INSPECTION PROCEDURES USED IP 37551:
Engineering Observations IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems j
IP 61720:
Containment Leak Rate Testing j
IP 61726:
Surveillance Observations lP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support and Observations IP 92700:
Onsite Followup of Written' Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Followup - Operations
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IP 92902:
Followup - Engineering IP 92903:
Followup - Maintenance IP 92904:
Followup - Plant Support IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors i
ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/98018-01 NCV issuing Procedure 9080.21, Revision 20 without conducting an
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adequate safety review.
50-461/s8018-02 NCV Failure to adhere to working hour limitations.
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50-461/98018-03 NCV Failure to properly test ERAT LTC operation.
Closed 50-461/97014-01A VIO Failure to refer to electrical diagrams during ground isolation activities.
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50-461/97014-02 VIO Failure to use proper procedures.
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50-461/97014-03 VIO Failure to adequately illuminate the protected area.
50-461/97022-02 VIO Failure to control copies of vendor manual.
50-461/97022-03 VIO Failure to prepare maintenance work documents.
50-461/97022-04 IFl Training on use of additional operator resources during event response.
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l 50-461/97-033 LER Misinterpretation of TS bases results in failure to meet required
actions for two inoperable emergency core cooling subsystems.
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I 50-461/97999-02 IFl LPCS alarm set point is above relief valve set point.
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50-461/97999-18 IFl Excessive use of overtime.
50-461/97999-21 IFl
. incorrect indications on remote shutdown panel.
L 50-461/97999-24 IFl Reasonable assurance does not exist for maintaining and l
implementing the design basis for the low pressure coolant
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injecaon (LPCI) mode of residual heat removal (RHR).
50-461/98002-04 URI Review of licensee's control of personnel hours of work.
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50-461/98003-07 NCV Failure to ensure RYJ testing was included as part of test control program.
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50-461/98003-08 NCV Failure to conduct an adequate 10 CFR Part 50.59 evaluation screening when changing the testing methodology for the diesel ventilation system.
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50-461/98011-07 URI Evaluate the hazards of transporting anhydrous ammonia.
50-461/98018-01 NCV lssuing Procedure 9080.21, Revision 20 without conducting an adequate safety review.
l 50-461/98018-02 NCV Failure to adhere to working hour limitations.
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50-461/98018-03 NCV Failure to properly test ERAT LTC operation.
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PERSONS CONTACTED Licensee
W. MacFarland IV - Chief Nuclear Officer l
G. Hunger, Plant Manager - Clinton Power Station
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W. Romberg, Manager - Nuclear Station Engineering Department R. Phares, Manager - Nuclear Safety and Performance improvement G. Baker, Manager - Quality Assurance l
' J. Goldman, Manager - Work Management l
V. Cwietniewicz, Manager - Maintenance J. Gruber, Director - Corrective Action l
W. Maguire, Director - Operations J. Sipek, Director - Licensing D. Smith, Director - Security and Emergency Planning
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. LIST OF ACRONYMS C&l Control and instrumentation CR
. Condition Report -
ECCS-Emergency Core Cooling Systems EDG
' Emergency Diesel Generator EOP Emergency Operating Procedure ERAT Emergency Reserve Auxiliary Transformer HPCS High Pressure Core Spray -
' LLRT -
Local Leak Rate Testing LPCI Low Pressure Coolant injection LPCS Low Pressure Core Spray LTC=
Load Tap Charger NLO Non-Licensed Operator OD Operability Determination
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_OSC-
. Operations Support Center
.PM Preventive Maintenance RAT Reserve Auxiliary Transformer RCIC Reactor Core isolation Cooling.
RHR Residual Heat Removal RTD-Resistance Temperature Detector QA
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Quality Assurance
- SDFV System Design and Functional Validation SED Station Emergency Director SET Special Evaluation Team c
SMCR Simulator Main Control Room -
STS Self Test System c
TS Technical Specification TSC-Technical Support Center
.USAR-Updated Safety Analysis Report
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