IR 05000461/1999011
| ML20206G984 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 04/30/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20206G973 | List: |
| References | |
| 50-461-99-11, NUDOCS 9905110005 | |
| Download: ML20206G984 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONll!
Docket No: 50-461 License No: NPF-62 Report No: 50-461/99011(DRP)
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Licensee: lilinois Power Company l
Facility: Clinton Power Station Location: Route 54 West Clinton,IL 61727 Dates: April 8 - April 21,1999 Inspectors: T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector D. S. Butler, Senior Reactor Engineer
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Approved by: Thomas J. Kozak, Chief Reacto; Projects Branch 4 Division of Reactor Projects s
9905110005 990430 PDR 0 ADOCK 05000461 PM
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EXECUTIVE SUMMARY Clinton Power Station NRC Inspection Report 50-461/99011(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 2-week period of resident inspection.
Ooerations
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The licenaee implemented or planned several interim corrective actions designed to sustain adequate performance in the operations functional area through restart.
However, long-term corrective actions described in the Plan-For-Excellence had not been scheduled for completion following restart of the facility (Section 08.1).
. The licensee's planned corrective actions to resolve deficiencies in the work control process were considered adequate to support closure of this aspect of NRC Manual
' Chapter 0350 Case-Specific Checklist (CSC) Restart item 11.1, " Establish and implement Continuing Operator Training Emphasizing Technical Specification Adherence / Knowledge and Recognition of Degraded Conditions." However, the effectiveness of the licensee's planned corrective actions to sustain improvement is considered an inspection Follow-up item. Licensee actions to address the other aspects of this CSC restart item were documented in NRC Inspection Report 50-461/99006.
Based on the inspection results documented in that report and this report relative to CSC Restart item 11.1, this item is considered closed (Section O8.1).
Enaineerina
.- One violation was identified due to the failure of the engineering staff to assure that design basis information regarding the horsepower rating for the hydrogen mixing compressors was correctly translated into emergency diesel generator loading calculation 19-AK-05, despite having considered this issue closed in the corrective action system (Section E1.1).
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The inspectors concluded that the electrical distribution system design changes would resolve degraded voltage concems and would restore Clinton Power Station to the original design basis by having an automatic degraded voltage detection scheme.
Consequently, NRC Manual Chapter 0350 Case Specific Checklist Restart Item IV.4,
" Resolve Degraded Voltage and Electrical Distribution," is considered closed (Section E8.1).
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The inspectom concluded that the operability determinations, operability evaluations, and safety evaluations adequately addressed all modes of plant operation with current
- setpoint field settings. In addition, the inspectors concluded, based on their evaluation of sixteen instrument setpoint review packages, that the licensee had adequately demonstrated that sufficient margin existed between the field settings and their respective allowable value ar;d analyticallimit. Consequently, NRC Manual Chapter 0350 Case Specific Checklist Restart item VI.3, " Validate the Adequacy of the i Setpoint Program," is considered closed (Section E8.2). !
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l One non-cited violation was identified due to the failure to stage alternate fire protection i
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equipment following the removal of hydrant house 31 from service. The failure of operations personnel to communicate the status of disabled fire protection equipment to fire brigade members was considered a weakness (Section F2.1). ;
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Report Details Summary of Plant Status The plant remained shutdown during the inspection period. Major plant activities involved divisional outages to prepare the plant for Mode 1 and 2 operations.
l. Operations 08 Miscellaneous Operations issues (92901,92903)
08.1 . (Closed) Case Specific Checklist Restart item l1.1. " Establish and Implement Continuina Ooerator Trainina Emohasizina Technical Specification Adherence /Knowledae and Recoanition of
Dearaded Plant Conditions":
- The initial review of Case Specific Checklist (CSC) ltem II.1 was documented in NRC Inspection Report 50-461/99006.
One aspect remained unreviewed which involved an assessment of the work control to operations interface.
The inspectors assessed the licensee's root cause analyses, apparent cause analyses, self-assessments, and corrective actions for issues involving the use of coordination plans, system impact statements, the development and completion of post-maintenance testing, equipment status control, and awareness of operations personnel.
Coordination plans and system impact statements The licensee initiated Condition Report (CR') 1-99-02-381 on February 23,1999, to conduct a root cause analysis for not implementing coordination plan (CP)99-003 during the tie-in of a feedwater keep fill system modification to the residual heat removal system. Specifically, CP-99-003 specified that during the system connection, shutdown cooling would be taken from an operable status to an available status due to a seismically unanalyzed condition. Because operations personnel did not adequately review CP-99-003, the applicable Technical Specification (TS) was not entered.
Subsequent to the event, the licensee completed calculations and determined that the pipe stresses for the interim con 6guration were below the ASME code allowed value and therefore, did not impact operability of the shutdown cooling system. The inspectors agreed with the results of the calculation.
The licensee determined that the root cause for the event described in CR 1-99-02-381 was ineffective communication of the CP's content and potential impact on the plant.
Contributing factors were the failure of operations personnel to read CP-99-003 before allowing work to proceed and the failure to integrate the CP into the goveming work document. The licensee also reviewed the results of common cause analyses for several recent work management issues captured in various condition reports. Based on the common cause analyses, the licensee identified weak process barriers relative to job stepping / pre-planning, the development of coordination plans, communication of job scope changes, and operations review during the preparation of work packages.
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The licensee developed several corrective actions in response to the event described in CR 1-99-02-381. The planned corrective actions included assigning additional operations department reviewers to ensure operational impacts were identified in work packages; revising Procedure 1029.03, " Implementation of Fix-lT-Now (FIN) Process,"
and Procedure 1029.01, " Action Requests and Maintenance Work Orders," to require the use of a system impact statement in work packages; reinforcing expectations for the review of work package job steps;' adding anticipated TS actions to the daily schedule; identifying work activities that impact key safety functions on the daily report; revising Procedure 1151.01, "On-line Work Management Process," and Procedure 1151.04,
" Outage Planning and Preparation," to require the scheduling of post-maintenance testing activities; and requiring an on-shift operations management signature on coordination plans before field implementation.
The licensee also planned to self-assess activities involving the use of system impact statements and the development and implementation of cps. As a method of trending performance, the licensee planned to use a barrier analysis matrix in work week manager performance reports until the end of 1999. The inspectors considered the licensee's planned corrective actions adequate to address the concerns associated with cps and system impact statements.
Development and performance of post-maintenance testing The licensee initiated CR 1-99-03-063 on March 4,1999, to conduct a root cause analysis for errors and omissions in the post-maintenance testing (PMT) program. The licensee determined that PMT program implementation was closely aligned with procedural requirements. However, the PMT program did not meet industry standards described in Electric Power Research Institute document NP-7213, " Post Maintenance Testing Reference."
The licensee determined that the root cause for the issue described in CR 1-99-03-063 ,
was management's failure to dedicate adequate resources to improve the planning /PMT process and keep it current with industry norms. Contributing causes were the use of
' informal control mechanisms and confusion between departments over responsibilities.
The inspectors determined that while the magnitude of the problem was less, the root cause was similar to the root cause identified by the licensee's Independent Safety Assessment (ISA) team conceming the PMT program.
- The corrective actions to improve the PMT program consisted of, in part, a review of work packages by operations, planning, and engineering personnel to determine if the appropriate PMT had been specified and completed, a comparison of the PMT program to industry best practices, a planned revision to the PMT program to incorporate industry information, development of a mechanism to track work packages awaiting PMT, and development of a PMT checklist for each work package. In addition, the licensee planned to conduct self-assessments to evaluate the effectiveness of the implementation of the corrective actions. The inspectors considered the planned short-term corrective actions to address the contributing factors adequate.
The inspectors determined that the licensee had not implemented most of the long-term corrective actions associated with Plan-For-Excellence (PFE) Item 40312, " Define and
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Develop the Post Maintenance Testing Program." The PFE Suramary, submitted to the NRC in February 1998, defined recovery / restart issues as those activities necessary to support safe operations. Long-term improvements were defined as those activities for which Illinois Power was not applying resources, and which were scheduled and planned for completion after startup. The inspectors subsequently determined that due dates did not exist for the long-term actions described in the PFE Summary, The licensee stated that following restart of the facility, emphasis would be placed on updating the long-term improvement initiatives and scheduling the items for completion.
The inspectors determined that no corrective actions were documented in CR 1-99-03-063 for the root cause and that the extent of condition for the root cause was ;
not assessed. In addition, the root cause quality checklist was not completed by the {
maintenance department to ensure that corrective actions and the extent of condition evaluation were adequate. The use of the root cause quality checklist for all level 1 or 2 CRs was discussed as a corrective action at a public meeting with the NRC in Decernber 1998 in response to poor quality root cause analyses.
On April 14, the licensee informed the inspectors that corrective actions to address management's failure to dedicate adequate resources to improve processes and keep them current with industry norms had been specified in PFE action items. Additionally, l the extent of condition was addressed during PFE program readiness reviews for restart of the facility. The licensee added a memorandum to the file for CR 1-99-03-063, from the root cause investigator, to link the PFE corrective actions and program readiness )
reviews to the CR. The inspectors considored the licensee's planned corrective actions described in the PFE adequate to resolve this issue.
On April 16, in response to the inspectors' observations, the licensee completed a review of the use of the root cause quality checklist. Corrective action group personnel determined that 17 of 22 root cause evaluations conducted since December 1998, either did not use the root cause quality checklist or retain a copy of the checklist with the CR.
In response to the deficiency, corrective action group personnel issued a memorandum on April 16 to reinforce management's expectations that personnel complete the root cause quality checklist for level 1 and 2 CRs. The inspectors determined that the use of the checklist is not required by plant procedures.
Equipment status control Between July 1,1998 and April 1,1999, there were approximately 32 valve or breaker mispositioning events. On March 5,1999, the independent analysis group forwarded a memorandum to the operations department stating that an analysis of mispositioning events indicated that operations personnel were the largest contributor to valve and breaker misalignments.
Operations personnel subsequently initiated an action to segregate the mispositioning events into categories involving the time of occurrence and the discovery method. In addition, the licensee planned to develop a performance monitoring goal to track and trend future mispositioning events.
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Prior to restart of the facility, the licensee planned to conduct system alignments on most plant systems. Plant systems not validated by a recently completed valve and breaker lineup were limited to systems already in-service and components impacted by radiation dose considerations. The inspectors determined that the completion of the system alignments provided reasonable assurance that valves and breakers would be configured in accordance with plant procedures before restart of the facility.
Awareness of operations personnel On February 12,1999, quality assurance (QA) personnel initiated CR Q-99-02-186 due to a lack of operator awareness of plant equipment status. The CR was initiated following the results of a continuos control room observation conducted by QA personnel.
The licensee determined that the identified inappropriate actions by operations personnel were due to inconsistent and less than adequate behaviors of main control room personnel. The root cause of the inappropriate actions was the failure of shift and plant operations management to consistently communicate, reinforce, and hold personnel accountable to management expectations and standards. In addition, the licensee determined that shift personnel had not fully internalized accountability and ownership values. The inspectors determined that while the magnitude of the problem was less, the root cause for the lack of operator awareness was similar to the root cause for performance deficiencies identified by the NRC Safety Evaluation Team (SET).
Recommended corrective actions by the licensee involved the development of a model for a plant operational focus, establishing a voice mail system to enhance communications between operating crews, communicating expectations to modify control room behaviors, continued monitoring of control room activities, continued use of shift mentors, continued use of the event free observation cards, continued assignment of areas of responsibility to shift managers, and a meeting with senior reactor operators to discuss recent operational events and expectations.
On April 14, the inspectors questioned the effectiveness of pre-established programs (continued monitoring of control room activities, continued use of shift mentors, continued use of the event free observation cards, and continued assignment of areas of responsibility to shift managers) given the repetitive behavioral deficiencies. The inspectors also questioned if an assessment had been conducted to determine the effectiveness of operations department self-assessment programs designed to improve behavioral attributes.
In response, the licensee stated that improvement had been observed in selected areas (communications, peer checks, and requalification training) but that continued improvement was still needed. Additionally, operations personnel stated that the operations department focus areas for improvement were self-assessments and corrective actions, main control room conduct, work management, panel walkdowns, and supervisory oversight. The inspectors determined that the focus areas related to concerns primarily identified by external assessments of plant operations and not through the development of precursor identification measures.
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On April 15, the licensee developed corrective actions involving a review of the operation's department self-assessment programs to determine why the programs have been ineffective in identifying the issues in CR Q-99-02-186 and those identified through NRC inspections.
I Inspectors assessment of licensee corrective actions I j
The inspectors concluded that licensee corrective actions to address operator performance concerns had resulted in limited irnprovement in routine plant operations ]
l performance. Several interim corrective actions were implemented to sustain these i improvements through restart of the facility. However, long-term corrective actions j described in the PFE had not been initiated or scheduled for completion. l The inspectors determined that the licensee developed and planned to implement several corrective actions to improve the work control to operations interface. However, the inspectors were unable to assess the effectiveness of the corrective actions.
Consequently, the effectiveness of the licensee's planned corrective actions to improve the work control process is considered an inspection Follow-up Item (IFl 50 461/99011-01).
111. Enaineerina E1 Conduct of Engineering E1.1 Inadeauste Resolution of Hydroaen Mixina Comoressor Horsepower Ratina a. Inspection Scope (37551)
The inspectors reviewed calculation 19-AK-05, " Calculation for Diesel Generator Load
- Monitoring," Revision 5, to ensure that previous!y identified deficiencies regarding the horsepower (Hp) rating of the hydrogen mixing compressors were appropriately addressed.
b. Observations and Findinas l In July 1997, the inspectors reviewed calculation 19-AK-05 and Updated Safety Analysis Report (USAR) Table 8.3-13, " Plant Loads," and determined that the Hp rating for the hydrogen mixing compressors had been inappropriately reduced from 60 Hp to 35 Hp.
This issue was documented in NRC Inspection Report 50-461/97015 as a violation of Criterion lli of Appendix B to 10 CFR Part 50, in response to the issue, engineering personnelinitiated CR 1-97-07-105 and an engineering evaluation. Based on the engineering evaluation, the licensee determined that the emergency diesel generators were capable of supplying the additional hydrogen mixing compressor load. However, the licensee planned to revise calculation 19-AK-05 and USAR Table 8.3-13, to ensure that the proper hydrogen mixing compressor horsepower rating was included in the design basis documentation following the completion of the degraded voltage modification.
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l During the inspectors * review of the licensee's actions to resolve CSC Restart item IV.7,
" Resolve Emergency Diesel Generator Concerns," in January 1999, the inspectors identified that the licensee had justified the adequacy of corrective actions to address a restart item using the version of calculation 19-AK-05 which had been previously 1 identified as being deficient by the inspectors in 1997. The inspectors informed the licensee of the deficient calculation for a second time and discussed the issue with l engineering personnel. Engineering personnel informed the inspectors that a reviewed and approved revision to calculation 19-AK-05 would be completed prior to startup.
In April 1999, engineering personnel considered this issue closed in the correcFve action program and provided an approved copy of calculation 19-AK-05, Revision 5, to the inspectors for review. The inspectors reviewed the calculation and determined that the hydrogen mixing compressor horsepower information had not been corrected. This was '
considered to be of more than minor significance since the licensee had been informed of the incorrect calculation by the 'NRC in July 1997 and again in January 1999.
Engineering personnel initiated CR 1-99-04-122 to document the issue.
Criterion ill of Appendix B to 10 CFR Part 50, requires, in part, that measures be established to assure that the design basis for structures, systems, and components a e correctly translated into specifications, drawings, procedures, and instructions. The inspectors determined that the failure to appropriately translate design basis information regarding the horsepower required for the hydrogen mixing compressors into calculation 19-AK-05, Revision 5, was a continuing violation of Criterion lli of Appendix B to 10 CFR Part 50 (VIO 50-461/99011-02).
c. Corsclusion One violation was identified due to the failure of the engineering staff to assure that design basis information regarding the horsepower rating for the hydrogen mixing compressors was correctly translated into emergency diesel generator loading calculation 19-AK-05, despite having considered this issue closed in the corrective action system.-
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Case-Specific Checklist item IVA " Resolve Deoraded Voltaae and Electrical Distribution Concems": The initial review of this item was documented in NRC
- Inspection Report 50-461/99003. The inspectors reviewed reserve auxiliary transformer (RAT) static volt-ampere reactive compensator (SVC) test evaluation No. 0153-0009-35-RPT001 and emergency reserve auxiliary transformer (ERAT) static VAR compensator test evaluation 0153-0009-35-RPT002 to determine if the SVC additions would resolve degraded voltage and electrical distribution concerns. The
- inspectors also evaluated engineering personnel acceptance reviews of the SVC design verification tests. l Acceptance was based on CPS test 2825.17, " RAT /SVC Initial
- Energization Test;" test 2825.18, " RAT /SVC Integrated Test;" test 2825.36, " ERAT /SVC
- Initial Energization Test;" and test 2825.37, " ERAT /SVC Integrated Test." The test data results demonstrated that the RAT /SVC and ERAT /SVC response to small and large
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load changes would restore emergency bus voltages to their nominal value (4.16 kV) in l- less than 2 seconds. This confirmed that the bus specific degraded voltage relays would
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reset prior to relay time-out (14.6 seconds) during block starting of the emergency loads.
Acceptable emergency bus voltages were observed during these tests to ensure emergency loads would start, accelerate, and run within their operating limits.
The inspectors concluded that the electrical distribution system design changes would resolve the degraded voltage concems at Clinton Power Station. In addition, these changes would restore the plant to the original design basis by having an automatic degraded voltage detection scheme.
E8.2 - (Closed) Case Soecific Checklist item VI.3. " Validate the Adeauacy and Control of the Setooint Proaram": The initial review of this item was documented in NRC Inspection Report 50-461/99003. The inspectors assessed the adequacy of setpoint operability determination 1-98-07-308-OD, operability evaluation 1-98-07-308-OE-2, safety evaluation 99-081, and sixteen instrument setpoint review packages.
The inspectors assessed the licensee's actions to ensure TS required instrument setpoints were correctly set in the field. Operability evaluation 1-98-07-308-OE-2 assessed 750 instrument parameters related to Regulatory Guide (RG) 1.105, "Setpoints for Safety Related Instrumentation," Type A variables for RG 1,97, " Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," emergency operating procedures, and TS compliance to ensure instrument operability during all plant operating modes. The associated safety evaluation (99-081) addressed plant operation with the field setpoints designated as "use-as-is." The operability evaluation addressed setpoint calculation errors and inconsistencies; however, the licensee also identified that the existing field setpoints had been conservatively established for all plant operating modes. The inspectors examined three setpoint review packages covered by the safety evaluation.
In each case, the field cettings were set conservatively and provided sufficient margin from their respective TS allowable value and analyticallimit. The inspectors determined that the setpoints reviewed were operable and that the licensee had provided adequate justification to support the safety evaluation conclusion that the plant would be operated within it's original design and licensing basis.
The licensee identified thirteen setpoints that were not covered by operability evaluation 1-98-07-308-OE-2. These setpoint parameters were evaluated by the licensee separately through the CR process. Problems identified during the special evaluations involved several parameters that had non-conservative allowable values currently in the TS, such as reactor pressure vessel low water levels. Using a conservative setpoint methodology in the setpoint evaluations, the licensee determined that the current field settings were within their analytical limit and would not exceed the calculated allowable value over the parameters calibration period. Another identified problem pertained to several parameters that would require TS bases description changes, such as the thermal power flow-blas trip setpoint. Original safety analysis modeling credited the flow-bias trip for mitigating the loss of feedwater heating event.
However, the original two-dimensional safety analysis modeling code was determined by General Electric to be overly conservative. The NRC approved the use, at Clinton Power Station, of a three-dimensional safety analysis code which no longer credited the flow-bias trip for mitigating a loss of feedwater heating event, since the flow-bias trip setpoint would not be reached during this transient.
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rg The inspectors concluded that the operability determinations, operability evaluations, and safety evaluations adequately addressed all modes of plant operation with current setpoint field settings. In addition, the inspectors concluded, based on their evaluation of 16 instrument setpoint review packages, that the licensee had adequately demonstrated that sufficient margin existed between the field settings and their respective allowable value and analyticallimit.
IV. Plant Support F2- Status of Fire Protection Facilities and Equipment F2.1 Removal of Hydrant House 31 from Service a. Inspection Scope (71750)
The inspectors reviewed the licensee's implementaiion of compensatory measures following the removal of hydrant house 31 from service.
b. Observations and Findinas On April 14,1999, the inspectors completed a tour of outside areas in preparation for plant startup and identified that hydrant house (HH) 31, located east of the screen house,
' was out-of-service. This out-of-service condition also resulted in the hose racks in the screen house being inoperable. Fire protection personnel had placed a sign on HH 31 which stated that an additional fire hose was staged at HH 25 located west of the makeup water pump house. This additional fire hose was to be used in the event of a fire in the screen house. The inspectors determined that the sign placed on HH-25 conflicted with the sign on HH 31. Specifically, the sign on HH 25 stated that an additional fire hose for HH 31 was staged at the screen house. A specific location for the staged hose was not given. Fire protection personnel concurred that inadequate information was on the posted signs.
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The inspectors questioned fire protection personnel regarding the conflicting signs to determine whether adequate fire hose had been staged to enable the licensee to -
effectively fight a fire at the screen house. Fire protection personnel informed the inspectors that approximately 900 feet of hose was staged inside HH 25; however, additional compensatory measures needed to combat a potential fire in the screen house were not properly. implemented. Specifically, the hose station located inside the "B" fire
. pump room did not have a gated wye connection, a sign, or additional hose staged as required by procedure.-
Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978. Section 1.L of
- Appendix A to RG 1.33 recommends procedures for the fire protection program.
Procedure 1893.01, " Fire Protection impairment Reporting," Appendix A, states that if one or more of the fire hose stations are inoperable, provide a gated wye connection on the nearest operable hose station. One outlet of the wye shall be connected to the standard length of hose provided for the hose station. The second outlet of the wye shall
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be connected to a length of hose sufficient to provide coverage for the area left unprotected by the inoperable hose station. The failure to have a gated wye connection and appropriate lengths of fire hose attached to the wye connection at the screen house, as required by Procedure 1893.01, is considered a violation of TS 5.4.1.a. However, this Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-461/99011-03). This violation is in the licensee's corrective action program as CR 1-99-04-219.
During subsequent discussions, the inspectors questioned fire protection personnel to determine whether the status of HH 31 was communicated to all fire brigade members.
Fire protection personnel informed the inspectors that operations personnel / fire brigade members involved in taking HH 31 out-of-service were awcre of the equipment's status.
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However, the status of HH 31 was not communicated to the other fire brigade members.
The inspectors considered this a weakness in the fire protection program. The licensee was taking action to improve the communication of disabled fire protection equipment status to fire brigade members at the conclusion of the inspection, c. Conclusion One non-cited violation was identified due to the failure to stage alternate fire protection equipment as required by Procedure 1893.01 following the removal of hydrant house 31 l
from service. The failure to communicate the status of disabled fire protection equipment to the appropriate fire brigade members was also considered a weakness.
l V. Manaaement Meetinas j X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the I conclusion of the inspection on April 21,1999. The licensee acknowledged the findings j presented. The inspectors asked the licensee whether any materials examined during the i inspection should be considered proprietary. No proprietary information was identified.
X3 Management Meeting Sumrnary On April 16,1999, a public meeting was held on-site to discuss licensee restart activities and performance improvement initiatives,' as well as NRC activities associated with implementation of NRC Manual Chapter 0350, " Staff Guidelines for Restart Approval." Specific topics included power ascension, long-term improvement, the feedwater keep fill modification, and the status of
~ licensee actions to address Case-Specific Checklist restart items.
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PARTIAL LIST OF PERSONS CONTACTED i
Licensee-j l
G. Baker, Manager - Quality Assurance l
. V. Cwietniewicz, Manager - Maintenance ' )
J. Goldman, Manager - Work Management !
J. Gruber, Director - Corrective Action
~ P. Hinnenkamp, Assistant Plant Manager
' G. Hunger, Plant Manager - Clinton Power Station
- W. Maguire, Director - Operations J. McElwain - Chief Nuclear Officer
' R. Phares, Manager - Nuclear Safety and Performance improvement J. Sipek, Director- Licensing D. Warfel, Manager - Nuclear Station Engineering Department INSPECTION PROCEDURES USED lP 37551: Engineering Observations IP 71750- Plant Support IP 92901: Followup - Operations IP 92902: Followup - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/99011-01 IFl Review of long-term corrective actions to sustain performance in the operations functional area.
150-461/99011-02 VIO Failure to assure design basis information for the hydrogen mixing compressors was translated into a safety-related calculation.
50-461/99011-03 NCV Failure to provide temporary protection to reduce a plant vulnerability to a fire.
Closed
'50 461/99011-03' NCV Failure to provide temporary protection to reduce a plant vulnerability to a fire.
CSC Restart item 11.1
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- Establish and Implement Continuing Operator Training Emphasizing Technical Specification Adherence / Knowledge and Recognition of Degraded Conditions CSC Restart item IV.4 Resolve Degraded Voltage and Electrical Distribution Concerns CSC Restart item VI.3 - Validate the Adequacy of the Setpoint Program i
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LIST OF ACRONYMS USED CP Coordination Plan
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CPS . Clinton Power Station
'CSC. Cese Specific Checklist
'CR Condition Report ERAT Emergency Reserve Auxilary Transformer FIN Fix-It-Now
'HH Hydrant House IP. lilinois Power ISA . ' Independent Safety Assessment PFE- Plan For Excellence PMT Post-Maintenance Testing QA Quality Assurance RAT. Reserve Auxiliary Transformer RG Regulatory Guide SVC Static Volt-Ampere Reactive Compensator.
SET Special Evaluation Team TS Technical Specification USAR Updated Safety Analysis Report l
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