IR 05000266/1997010
| ML20217A273 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 09/15/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20217A255 | List: |
| References | |
| 50-266-97-10, 50-301-97-10, NUDOCS 9709190114 | |
| Download: ML20217A273 (49) | |
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l U.S. NUCLEAR REGULATORY COMMISSION REGION lll Docket Nos:
50 266, 50-301 License Nos:
50 266/97010(DRS); 50-301/97010(DRS)
Licensee:
Wisconsin Electric Power Company
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Facility:
Point Beach Nuclear Plant Locations:
6612 Nuclear Road Two Rivers, WI 54241 9516 Dates:
May 19 - June 13,1997 Inspectors:
D. Butler, Reactor Engineer, Team Leader R. Winter, Reactor Engineer, Assistant Team Leader J. Lennartz, Operator Licensing Examiner N. Jackiw, Reactor Engineer M. Holmberg, Reactor Engineer i
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J. Segala, Office of Nuclear Reactor Regulation Approved by:
J. W. McCormick Barger, Team Leader Point Beach Oversight Team l
9709190114 970915 PDR ADOCK 05000266 G
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EXECUTIVE SUMMARY
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l Point Beach Nuclear Plant, Units 1 and 2 NRC Inspection Report 50 266/97010(DRS); 50 301/97010(DRS)
This special startup issues inspection was initiated following the identification ; f significant problems in maintenance, operations and engineering support at Point Beach. The inspection was conducted at Point Beach Nuclear Plant from May 19,1997, through June 13,1997.
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Control room activities showed improvement in the areas of command and control, and o
communications (Section 01.1).
Licens ne actions to complete commitments associated with procedure reviews and o
upgrac es were adequate to meet the commitment requirements (Section 03).
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Operators obtained the correct results using an incorrect procedure step. The o-inepectors were concerned that operators were reluctant to change incorrect procedure steps and were willing to accept poorly written procedures (Section 03.3).
Operations staff identifW that many procedures required revisions. The licensee has o
initiated a procedure upgrade program (Section 03.4).
The industry Experience Review Program appeared to seek a thorough understanding o
of industry issues which were applicable to Point Beach (Section 04.1).
Maintenance Overall, reviews of present and past maintenance and work activities were performed in o
- a satisfactorily manner (Section Ml).
The licenses satisfactorily reviewed all non pump and valve surveillance tests to ensure o
design basis performance met procedure acceptance criteria (Section M3.1.b.1).
Changes made to the inservice testing program did not meet original plant commitments o
and required additional clarification before commitment item 35 could be closed (Section M3.1.b.4).
Engineering Unit 2 degraded equipment evaluations were completed by the licensee in a o-satisfactorily manner. However, the inspectors identified one Unit 1 degraded equipment item involving a frozen main steam blowdown valve where the licensee had not fully addressed whether the pipe and valve design limits had been exceeded. The inspectors were concerned that Unit i deficiencies may not have received the same resolution rigor that Unit 2 equipment received (Section E1.1.b.1).
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- c The licensee effectively implemented dedicated review groups consisting of system o
engineers and managers to ensure degraded equipment issues weia identified and resolved before Unit 2 restart (Section E1.1.b.1).
The inspectors identified a violation for not writing a condition report to address o
emergency diesel generator operability when the voltage monitoring relay was found out of-calibration (Section E1.1.b.2).
improvements were made in the 10 CFR 50.59 screening and safety evaluation o
processes. Proper references existed for the inspectors to independently determine that unreviewed safety questions did not exist for safety evaluation screenings performed during 1996 and during the Unit 2 refueling outage (Section E.1.2).
The inspectors identified that the response to a previous Notice of Violation was o
inaccurate. The licensee stated, in part, that the Unit i reactor trip bypass breaker 90 millisecond opening time was bounded by all known historical test data; however, the
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inspectors identified a data point that was not bounding, in addition, the licensee could not provide the statistical basis for the 90 millisecond value (Section E1.3),
Recently implemented changes in the Design Bases Document (DBD) program o
appeared to add programmatic guidance to evaluate and timely disposition open DBD items which had potential system operability impact (Section E1.3).
Control Room Emergency Filtration system testing appeared to provide reasonable o
assurances that the system could perform its safety function (Section E2.1).
The inspectors concluded that the licensee adequately addressed molded case circuit o
breaker issues and the lack of coordination (Section E2.3).
Numerous Appendix R deficiencies were identified by the licensee during condition o
report reviews and during the Appendix R rebaselining reviews. Four apparent violations were identified regarding these Appendix R deficiencies. These violations
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represent a significant break down in engineering staff's evaluation of Appendix R issues at Point Beach, The safety consequences are significant in that safe shutdown of a unit in response to a fire and a loss of offsite power may not have been obtainable (Section E2.5).
Improvements have been made in the licensee's timeliness and sensitivity in resoiving o
and identifying conditions adverse to quality (Section E2.5.b.4).
The inspectors identified a violation for performing welds without a qualified welding o
procedure during the Unit 2 steam generator replacement project (Section E3.1).
The inspectors concluded that the System Engineering Review Board and Oversight o
Review Board appeared to ask critical questions and sought a thorough understanding of relevant issues (Section E4.1).
Condition reports reviewed by the inspectors appeared to be conservative and changes o
to the condition reporting system added appropriate guidance to ensure consistent and timely disposition of deficiencies (Section E7.1).
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- 6 Reoort Details Summary of Plant Status Unit 1 remained in cold shutdown following repair of two cooling water pumps and Unit 2 was in cold shutdown to refuel and replace its steam generators. During the past year, significant weaknesses in operations, maintenance, and engineering were identified at Point Beach.
These weaknesses encompass programmatic problems with conduct of operations, procedures, work and test activities, licensing and design bases adherence, and the corrective action program.
The purpose of this inspection was to examine and verify that Point Beach had thoroughly and effectively addressed many of the commitment items discussed in a December 12,1996, letter from the licensee to the NRC, and subsequently modified by letters dated June 13 and July 7, 1997, and resolved other identified startup issues. The inspectors performed an in-depth, muld-disciplinary review of operations, maintenance, testing, and engineering issues. In addition, the inspectors evaluated Point Beach's effectiveness in identifying, resolving, and preventing problems that degrade the quality of plant operations. This included evaivating the licensee's ability to identify if a safety evaluation should be performed dudng the screening process and that the safety evaluation adequately addressed if an unreviewed safety question existed.
Particular emphasis was placed on reviewing the conduct of operations,50.59 screenings, safety evaluations, condition reports, prompt operability determinations, and engineering calculations.
The licensee has made many charges to the 50.59 screening and safety evaluation process, the condition report process, the design bases document review process, and the work order process. Many of these process changes were recently implemented. The inspectors could not effectively assess implemertation of some of the recent changes. These processes will be
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looked at in future inspections to ensure that the changes were effectively implemented.
Overall, the inspectors concluded, in general, that Point Beach satisfactorily addressed the commitment items that were reviewed by the inspectors. Even though some items, such as appendix R modifications, were in the implementation phase, conceptually, the proposed actions appeared to have alleviated the identified discrepancies.
Wisconsin E!ectric (WE) commitment numbers identified in the December 12,1996, letter and subsequently modified by lettars dated June 13 and July 7,1997, were used to identify items reviewed by the inspectors. Attachments A, B, C, and D provide a list of additional documents reviewed.
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1. Operations
Conduct of Operations 01.1 Control Room Observations a.
Insoection Scooe
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The inspectors observed individual "watchstation" turnovers, crew briefings, and control room conduct of operations.
b.
Observations and Findings Control room command and control was noticeable as evidenced by the various
"watchstanders" announcing to the Duty Operating Supervisor (DOS) when they had assumed the " watch station" following turnover. Additional evidence of command and
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control was demoritrated by personnel asking the DOS permission prior to entering the control room, in one instance, an individual who entered the control room without prior permission from the DOS was counseled immediately by the Duty Shift Supervisor (DSS) regarding this practice. There were a few instances where personnel who had ente.ed the control room prior to receiving permission from the DOS immediately i
recognized their error, exited, and then requested permission to enter. The insoectors also observed a DOS request two individuals carrying on a conversation that was not part of crew activities to leave the control room.
Crew communications, acknowledgments and repeat backs were clear. Control room crews used the phonetic alphabet regularly when communicating status of plant equipment. In most cases, the DSS corrected crew communication deficiencies on the spot.
Control Operator (CO) turnovers included a t ard walkdown with their counterpart on the applicable unit to discuss system configurations and standing annunciators. The oncoming DSS and DOS conducted a board walkdown on both units with their counterparts which also included system configuration and lit annunciator status discussions. The off-going third control room Senior Reactor Operator (SRO) relieved the off-going DOS of control room responsibility during turnover which allowed the off-going DOS to provide a more thorough turnover to oncoming personnel. The oncoming third control room SRO participated in the turnover with the oncoming and off-going DOSS.
The entire oncoming crew was briefed by the DSS outside the control room before assuming "watchstation" duties. All crew members provided input regarding plant and system status specific to their "watchstation." Operations management, chemistry, and engineering representatives were observed at the day and evening shift crew briefs.
The Unit CO regularly announced arnunciators to the DOS and referenced the annunciator response procedures, in some instances, the CO informed the DOS of an expected alarm due to on-going work activities prior to the alarm actuating. The observed COs' alarm responses were timely and they ensured that the DOS acknowledged their annunciator reports.
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C&nclusions The inspectors concluded that control room conduct of operations was adequate and improved in the area of command and control, and communications since the December 1996 Operational Safety Team inspection. The inspectors considered the shift turnovers and crew briefings to be effective.
O2 Operational Status of Facilities and Equipment
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02.1 WE Commitment Iteru16: " Review outstanding JCOs. Perform operability determinations and 50.59 evaluations needed to address the issues." This commitment was subsequently changed to " Resolve outstanding JCOs using out operability dewmination process and/or our 10 CFR 50,59 evaluation process,"by letter dated June 13,1997.
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Insoection Scooe The inspectors reviewed Unit 2 operability and/o. safety evaluations needed to support Justification for Continued Operation (JCO) determinations, b.
Observations and Findings The licensee and independent contractor personnel reviewed the four JCO's which were in use on both Units. The JCOs reviewed and dispositioned included:
JCO No. 2," Mechanical Plugs f ; Steam Generators." This JCO was canceled o
based on replacing Unit 2 steam generators which were not susceptible to the problem identified in the JCO.
JCO 94-07,"1&2W-001A-D1-M Containment Accident Fan Motors Unshielded o
Bearings " This JCO was canceled based on CR 97-0914 and the associated operability determination.
JCO 96-01, " Containment Fan Cooler Operation During a Design Bases o
Accident (DBA)." This JCO was canceled and replaced by interim Safety Evaluation Report (SER)97-003, JCO 94-03, " Direct Current (DC) Molded Case Circuit Breakers (MCCBs)." This o
JCO was initiated after a higher inan expected failure rate of MCCB magnetic trip elements. The JCO stated, in part, that the potential for magnetic trip element failure of the original design DC breakers was not an operability concern when single failure criteria was applied. However, the JCO identified that several non-safety related cables ware routed between redundant safety trains and in the same raceways. The potential existed for a common mode failure of a non-safety cable to cause the loss of both safety trains. The licensee concluded that the probability of such a fault was highly unlikely and that the upstream breaker should isolate the fault if it did occur. The MCCBs feeding the most vulnerable non-safety cables were replaced with an upgraded more reliable model. This JCO remains in effect; however, the licensee believes their planned MCCB operability evaluation will cancel this JCO before Unit 2 startup.
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Conclusions The documentation associated with the cancelled JCO's adequately demonstrated that the JCO's had been properly dispositioned. For JCO 94-03, the inspectors determined that it was a reasonable approach to prioritize the replacement of MCCBs which fed the more vulnerable non-safety cables. The licensee was procuring additional breakers for future replacements. The inspectors concluded that the licensee satisfactorily met commitment item 18.
Operations Procedures and Documentation O3.1 WE Commitment item 7: ' Complete a review of Unit 2 administrative controls implementing or referencing Technical Specifications to ensure Technical 3pecification requirements are appropriately reflected in the administrative controls. "
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Insoection Scoce The inspectors reviewed Unit 2 administrative controls which implemented or referenced Technical Specifications (TSs) to ensure that the TS requirements were appropriately l
reflected in procedures.
b.
Observations and Findings The licensee reviewed approximately 700 procedures for both units. In addition, an independent contractor reviewed approximately 74 of these procedures. The licensee generated Memo NPL-0048," Evaluation of PBNP Administrative Controls implementation of Technical Specification," which cross referenced Point Beach's TS to applicable implementing procedures. Condition Report (CR) 97-0831 was written to track any identified procedure discrepancies, such as missing, incorrect, or inconsistent references The licensee concluded that the identified discrepancies did not impact the TSs. The required changes were administrative in nature or appropriately classified as procedure enhancements. Operations Feedback Forms have been submitted to correct any procedure discrepancies during their next revision or at the latest by December 31, 1997. The inspectors independently verified that the identified discrepancies were administrative in nature and that the feedback forms had been written, c.
Conclusions The licensee's review was thorough with the majority of the identified procedure deficiencies being administrative in nature. Based on a review of the licensee's actions and an independent review, the inspectors concluded that the licensee satisfactorily met commitment item 7.
03.2 WE Commitment item 8: " Review 20% of the Operations TechnicalSpecification, inservice Test, and Operations Refueling Test related surveillance procedures, with concentration on those involving major equipment. Upgrade as necessary to include appropriate initial conditions, return to service lineups, properly specified independent verification, reviewing acceptance criteria, and Technical Specification implementation. "
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Inspection Scoce The inspectors reviewed the licensee's evaluation of Operations TSs, inservice Test (IT)
and Operations Refueling Test (ORT) related surveillance procedures. The review concentrated on those activities involving major safety equipment and focused on the adequacy of acceptance criteria, TS implementation, return to service lineups and independent verifications. The following procedures received an in-depth review by the inspectors:
IT-04 Low Head Safety injection Pumps and Valves IT-13 Component Cooling Water Pumps and Valves IT-115 Instrument Air Valves IT-215 SI Valves (Cold Shutdown)
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IT-325 Chemical and Volume Control System Valves (Cold Shutdown)
IT-525B Leakage Reduction and Preventive Maintenance Program Test of 2SI-896A&B St Pump Suction Valves TS-10A Containment Airlock Door Seal Testing ORT-6 Containment Spray Sequence Test ORT-9A Preparation for Integrated Leak Rate Test with Core Off Loaded ORT-10A Recovery from Integrated Leak Rate Test b.
Observations and Finding The inspectors determined that the licensee had completed their committed reviews.
Approximately 20% (52 procedures) of the 264 procedures in this population (14 TSs, 142 ITs,108 ORTS) were reviewed by the licensee, in addition, an independent contractor reviewed approximately 58 of these procedures. The contractors sample size included previously reviewed and non-licensee reviewed procedures. During a Pre-decisional Enforcement Conference held on September 12,1996, the licensee indicated that they would conduct a 100% population review of the above referenced procedures.
Completion of this review was scheduled for September 30,1997. The remaining reviews were currently in progress as part of the Procedure Upgrade Program. The inspectors reviewed the above listed procedures and did not identify any commitment discrepancies.
The licensee identified several procedure discrepancies that required reso!ution. For example, ORT-6, " Containment Spray Sequence Test for Unit 2," did not require an independent verification of shutting the spray isolation valves and racking the pump breakers to " Test" to prevent the containment spray system from spraying containment, in addition, ORT-3," Safety injection Actuation with Loss of Engineered Safeguards AC Unit 2" test procedure did not include independent verification for shutting the
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containment spray valves. The inspectors verified that the procedure changes needed to address the above examples had been incorporated into the Procedure Upgrade Program, c.
Conclusion The licensee adequately evaluated the operational procedures to ensure they contained appropriate procedure steps. The inspectors concluded that the licensee satisfactorily
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met commitment item 8.
03.3 Surveillance Test Observations a.
Insoection Scoce The inspectors observed test procedure IT-765, " Flow Test of High Head Safety _
Injection Check Valves (Refueling)," Unit 2, Revision 4, on June 4,1997. The
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inspectors also reviewed procedure IT-755," Flow Test of Low Head Safety injection Check Valves (Refueling), Unit 2," Revision 3.
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Observations and Findinas b.1 The licensee conducted a pre-test brief with allindividuals involved with IT-765. The test was supervised by the third control room SRO. The brief included a test overview, specific Instructions to individuals regarding out-plant actions, and a reminder to communicate clearly using three way communications. All appropriate points were covered during tne brief.
The test was well controlled and three way communications were utilized between the control room and out-plant operators. One incomplete repeat back from the CO running the test to an out plant operator was noticed and immediately corrected by the test SRO.
The test was completed without incident. However, IT-765, step 4.3.24, directed the CO
. to check valve operability by comparing valve data with limits in the " Inservice Testing (IST) Acceptance Criteria Binder." The inspector noted that the procedure step did not
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identify which check valve was being tested following various valve manipulations to realign systems flow paths. The CO had to obtain assistance from the SRO and use system flow diagrams to determine which check valve was being tested.
A licensee quality assurance (QA) observer questioned the CO and SRO about the procedure confusion. After three requests, the CO and SRO indicated that a CR and procedure feedback form would be written. CR 97-1798 and Operations Feedback Form IT-97-041 were issued on June 4,1997. In addition, the feedback form identified that procedure step 4.3.12 performed two actions in one step. -This did not meet management expectations that procedure steps should be clear and concise. The inspectors also identified that IT 765 procedure step 4.3.14 contained two actions in one step, "open 2SI-878C, then shut 2SI-878A." This step was added to the feedback form.
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c.1 Conclusions Procedure IT-765 was difficult to use but did not preclude successful test completion.
The proposed future changes were considered procedure enhancements. However, without a direct correlation between the procedure steps and the check valves being tested, the operators had difficulty verifying which valve was being tested. The inspectors concluded that the CR and Operations Feedback Form developed to address the procedural difficulties were submitted in a timely manner and were acceptable, b.2 The inspectors noted that IT 755 procedure steps 4.1.1,4.1.3,4.1.5 and 4.2.3 contained similar problems as identified in IT 765 regarding multiple actions contained in a single step. Also, IT 755 step 4.3 directed the operator to the " Operations Standing Order" to verify flow data. However, the " Operations Standing Order" does not exist any more. The procedure step should have directed the operator to the "lST Acceptance Criteria Binder."
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The inspectors reviewed IT 755, completed on June 4,1997, and identified that step 4.3 was signed off as completed without a notation that the procedure step was incorrect.
Operations management indicated that this was unacceptable and that an Operations Feedback Form would be completed to address the inspectors concem. Form, IT 97-042, dated June 15,1997, was written to address procedure step 4.3.
c.2 Conclusions Discrepancies identified in Procedure IT-755 did not preclude successful test completion. Referencing the " Operations Standing Order" did not result in any incorrect actions being taken, and had no safety consequences. The inspectors concluded that the procedure step discrepancy was minor. However, the operators obtained the correct results using an incorrect procedure step. The inspectors were concemed that operators were reluctant to change incorrect procedure steps and were willing to accept j
poorly written procedures. The inspectors concluded that the Operations Feedback Form adequately addressed the identified discrepancy; however, Operations was slow in initiating the form.
03.4 Procedure Revision Effort a.
insoection Scoce The inspector reviewed the procedure upgrade process. This included a short term plan to address immediate concerns before Unit 2 startup and a long term plan to upgrade all procedures.
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Observations and Findings The short term plan included directives from the Operations Manager to the procedure group and operations staff to not write any temporary changes to Emergency Operating Procedures (EOPs), Abnormal Operating Procedures (AOPs), and Administrative Procedures. In addition, WE internal correspondence from the Operations Manager, to the Piant Manager, dated June 11,1997, stated, in part, that all current temporary changes associated with these procedures were to be evaluated and appropriately
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dispositioned before Unit 2 startup. The tentative long term completion time was to upgrade the remaining procedures by mid 1998.
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Conclusions The inspector concluded that the procedure revision program had appropriate focus and prioritization.
Operator Knowledge and Performance 04,1 Industry Exoerlence Review Procram a.
Insoection Scong The inspectors evaluated the effectiveness of the Industry Experience Review Program by reviewing the licensee's process and several recently identified issues,
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Observations and Findinos l
The licensee's industry experience review process included performing reviews of operating experience reports, such as significant event reports (SERs), significant operating event reports (SOERs), and significant event notifications, generated by the institute of Nuclear Power Operations (INPO), NRC notifications, vendor reports, and reports from other facilities. Industry experience items were screened by a contractor.
The items were discussed with cognizant plant staff and applicable action items were designated for evaluation by staff experts. An industry experience newsletter was
added to plant bulletin boards and to corporate bulletin boards in Milwaukee. The NUTRK system was utilized to document industry and operational event issues.
Historically, some operational issues were screened with a narrow viewpoint which resulted in poor resolution of the issue.. However, recent industry experience issues.
have had good initial screenings and were being resolved in an appropriate manner.
Although no programmatic concems were identified, the inspectors noted that when the responsible program entry person was on vacation, backup personnel were not familiar with how to access the industry experience master computer file.
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Conclusions The inspectors concluded that the industry Experience Review Program appeared to seek a thorough understanding of industry issues which were applicable to Point Beach.
In addition, the inspectors noted that the licensee's operational experience feedback program notified the appropriate personnel about any applicable issues.
Operator Training and Qualification 05.1 WE Commitment item 76: ' Conduct round-table discussions with all MSS /SS/DTA personnelregarding conservative decision making, Technical Specification interpretations, and lessons teamed from recent regulatory communications and perspectives. Review outlier Technical Specification interpretations forinterim applications."
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insoection Scoce The inspectors reviewed Operations' round-table discussi:ns pertaining to conservative decision making, TS interpretations and lessons leamed from recent regulatory communications.
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Observations and Findings Topics pertaining to conservative decision making, TS Interpretations, and lessons learned from recent regulatory communications were discussed with Management Supervisory Staff (MSS), Shift Supervisors (SS), and Duty Technical Advisor (DTA)
personnel. The licensee developed a two hour training session including learning objectives. Two of the training sessions were observed by an independent contractor.
The contractor indicated that the training sessions were "well thought out and professionally presented." Fortpdght management individuals completed the training.
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The inspectors identified that six individuals recently assigned to one of the above target positions had not received the training, in addition, the inspectors identified that a mechanism did not exist to ensure all targeted management individuals had receiveo the required training. The licensee indicated that this training would be provided to the six individuals before Unit 2 fuelload.
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The licensee initiated Training Work Request 97-078 to include training on conservative decision making, TS interpretations, and lessons teamed from recent regulatory communications in the MSS initial and ongoing training programs, in addition, training on conservative decision making was to be included in the licensed operator initial training program, c.
Conclusions Based on the training provided and the training materials reviewed, the inspectors concluded that the licensee satisfactorily met commitment item 76. The licensee's actions to incorporate conservative decision making into the initial and ongoing training programs for targeted individuals were appropriate. However, the licensee had not initially ensured that a mechanism existed to identify newly assigned individuals that needed to complete the required training.
II. Maintenance M1 Conduct of Maintenance M1.1 WE Commitment Item 15: " Review 20% of the maintenance work orders performed since January 1,1995 on Unit 2 of common PSA safety significant systems (AFW, SW, EDG, IA,4.16 kv, gas turbine, and CCW) to verify adequate PMT was performed to ensure system / component safety functions."
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Insoection Scoce The inspectors evaluated past work orders to ensure they fulfilled maintenance work and post-maintenance testing requirements. This included a review of a sample of
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Unit 2 work orders performed since January 1,1995, on common safety significant systems and the work order system evaluation contained in QA Program Surveillance Report No. S-P-97-01, " Post-Maintenance Testing Performed on PSA Systems during 19951996 Work Orders."
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Qbservations and Findings Plant management assigned the QA organization to take the lead on this review activity.
A project plan was developed that established instructions for randomly selecting maintenance work orders, and a method for documenting the review results. The plan also required that all work orders be included (e.g., not just work performed by the maintenance group) and that the scope of the review should be expanded if significant or generic issues were identified in the original 20% review sample. The sample size had not been expanded by the end of the inspection.
The systems reviewed by the licensee included the auxiliary feedwater system; 4 kilo-
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volt (KV) system; component cooling water system; emergency diesel generators; gas turbine generator; instrument air system; and service water system. A total of 409 work orders were randomly selected from a population of 1944. Thirteen work orders were found to have problems, however, none of these resulted in inoperable equipment. In addition, nine Quality Condition Reports (OCRs) were written as a result of the review.
Problems described in the QCRs included not recording instrument indications, poor consistency in post-maintenance tests documentation practices, testing procedures were not clearly referenced in the work orders, poorly written work order test instructions, and poor practices in entering and exiting limiting conditions for operations, etc.
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The inspectors independently reviewed the following work orders (WOs):
I WO 9609063 P-38B AFP [ Auxiliary Feedwater Pump) Discharge to 2Hx-1B Steam Generator Stem Cleaning and Lubrication. Work order test details included the following: manually stroke the valve full open to full closed and verifying that the valve moves freely with I
no binding. The work order adequately addressed the maintenance and Post-Maintenance Test (PMT) to be performed.
WO 9609065 P-38A AFP Cooling Water Solenoid " Inspect, Clean and Maintain SOV (Solenoid Operated Valve)." The solenoid valve was cleaned and tested in accordance with test procedure IT-10. The work order adequately addressed the maintenance and PMT to be performed.
WO 9609071 P-38A AFP Discharge to Hx-1 A Steam Generator Check. The work order adequately addressed the maintenance and PMT to be performed.
WO 9609072 P-38B AFP Discharge to Hx-1B Steam Generator Check. The work order adequately addressed the maintenance and PMT to be performed.
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WO 9609077 Heat exchanger 4 ELHX Shell side Outlet Solenoid -
Overhaul / Rebuild SOV per ASCO 8316 instructions. The correct test procedure (PM-lT-65) was used to test the valve. In addition, the work order package contained the appropriate, controlled ASCO drawing. The work order adequately addressed the maintenance and PMT to be performed.
WO 97101356 Heater-exchanger 12D Outlet Safety Relief to T-12 CC (Component Cooling Water) Surge Tank. Inlet flange flexitallic leaking. The work order specified an acceptable leakage verification check.
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Conclusions The inspectors verified that work orders performed on sefety significant systems since January 1,1995, had been evaluated in accordance with the developed review plan.
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The inspectors concluded that the licensee satisfactorily met commitment item 15.
M3 Maintenance Procedures and Documentation M3.1 Surveillance Test (SVlt Post-Maintenance Test (PMTL and in-Service Test (IST)
Programs a.
-Insoection Scooe The inspectors evaluated the licensee's actions to ensure testing acceptance criteria satisfied equipment design bases, b.
Observations and Findinos b.1 WE Commitment item 12: ' Review 20% of the surveillance procedures with safety significant non-pump and valve components (such as heat exchangers and fans) to ensure that the surveillance acceptance criteria satisfy the requireme,nts of the plant design basis / accident analysis. Make changes as necessary as a result of this review."
The licensee exceeded their commitment to perform a 20 percent review of non-pump and valve surveillance test procedures by completing a 100 percent review (85 procedures). An independent review performed by a contractor included 3even of these procedures. The inspectors independently reviewed a sample of the non-pump and valve surveillances and determined that the tests contained appropriate acceptance criteria.
During the review, the licensee identified that procedure PC 56, Part 1 and Part 2,
" Containment Accident Recirculation Heat Exchanger Performance Monitoring Test,"
was inadequate. The procedure used installed instruments that lacked the accuracy needed to measure containment fan cooler performance. The licensee canceled this procedure and initiated procedure No. PBNP-40, " Performance Test of 1HX-15D " to test the Unit 1 accident fan coolers as part of the corrective actions designated in CR 97-0166.
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The inspectors reviewed procedure No. PBTP-40 performed on March 26,1996, and calculation No. PGT-PBNP-0006," Containment Air Recirculation Heat Exchanger 1HX-150 Thermal Performance Test Data Evaluation and Uncertainty Analysis " Based on this review, the inspectors determined that the Unit 1 containment fan coolers had heat removal capacity greater than the anticipated design basis heat loads. However, the inspectors observed that the new Unit 2 containment fan cooler test procedures lacked a scheduled completion date. This could result in not meeting Generic Letter (GL) 89-13 commitments which include annual containment fan cooler testing requirements. Since Unit 1 fan coolers passed their performance test, the inspectors believe Unit 2 fan coolers should also pass. The inspectors consider this an inspection followup item (50 301/97010-01(DRS) pending NRC review of the completed Unit 2 containment fan coolers performance test once it has been performed.
c.1 Conclusions The licensee reviewed all non pump and valve surveillance tests to ensure design basis
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performance met procedure acceptance criteria. The inspectors concluded that the licensee satisfactorily met commitment item 12. The licensee identified that the containment fan cooler performance test procedures were inadequate and planned to develop and implement new test procedures. The inspectors reviewed the new Unit 1 fan cooler performance test and found it to be acceptable, b.2 WE Commitment item 13' " Review other operating procedures that contain maintenance activities and revise as necessary to ensure PMT and OC are properly h
addressed by those procedures."
j The licensee reviewed a total population of 781 procedures to ensure that they contained appropriate PMT and quality control (QC) verifications. The licensee identified 70 procedures that needed additional PMT and/or QC involvement. Examples t
included: Operations Procedure OP-4d," Draining the Cavity and Reactor Coolant System with Fuelin the Vessel," that did not require PMT when a radiation controlled area level alarm setpoint was changed; OP-5A, " Reactor Coolant System Volume Control," that did not require PMT when the Reactor Coolant System level alarm setpoint was changed; and ORT-82, " Mechanical Penetration Leak Test," that did not require additional testing when its test procedure was revised.
Uniform review guidehnes for identifying weak PMTs were established by the licensee.
This document contained a listing of all procedures requiring revisions. The inspectors selected several procedures for review and confirmed that the procedures had been appropriately revised.
The licensee's independent assessment identified two items to be completed before Unit 2 restart. The first item provided operator guidance for improving MOV/AOV packing adjustments and manual valve closure steps for stopping sealleakage. The second item recommended that a OC witness point be used for verifying flange and torquing activities. Three additionalitems were identified as long term enhancements. The inspectors verified that all of the identified items were in the NUTRK system.
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s c.2 Conclusions Based on the procedure and documentation reviews and interviews with plant staff, the inspectors concluded that the licensee satisfactorily met commitment item 13.
b.3 WE Commitment Item 16: " Complete all Unit 2 Maintenance Rule related work order post-PMTs reviews prior to the approach to criticality."
The licensee completed a post PMT review of all Unit 2 Maintenance Rule related work orders. The inspectors reviewed NP 8.1.1, " Work Order Processing," and noted that the procedure contained instructions for processing Maintenance Rule related work orders.
For example, procedure Step 5.8 stated that a "retum to service testing review shall be
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prepared on all Maintenance Rule scope equipment and that these reviews shall be documented on a return to service form." In addition, procedure Step 5.10 stated,in part, that Maintenance Rule work orders were to receive an SRO review to ensure that work order initial conditions were appropriate, equipment recovery steps were
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acceptable, and appropriate independent verification had been performed. The inspectors reviewed a sample of the Maintenance Rule work orders and determined that appropriate PMT had been specified.
c.3 Conclusions Based on the procedure and documentation reviews, the inspectors concluded that the licensee satisfactorily met commitment item 16.
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b,4 WE Commitment Item 35: " Revise applicable ISTprogram documents to prevent equipment from being returned to service (declared operable) with vibration in the alert range * This commitment was subsequently changed to " Revise applicable ISTprogram documents to require the performance of an operability determination and NRC notification prior to retuming equipment to service in the event that equipment in Section XIinservice testing program have vibration levels greater than 0.325 (ps," by letter dated June 13,1997.
The licensee originally committed to revise IST program documents to prevent the retum to service of equipment with vibration levels in the alert range. The licensee revised procedure Operations Manual (OM) 4.2.2, " Inservice Tests" to meet this commitment. OM 4.2.2, paragraph 5.7, stated that " Pumps in the Section XI inservice testing program shall not be returned to service following maintenance activities with a vibration level of greater than 0.325 ips. If for some reason this requirement cannot be met, an Operability Determination will need to be performed and documented. The NRC shall also be informed that a regulato.y commitment is not being met...." The inspectors determined that the revised OM did not appear to meet the commitment wording, in that, the option to perform an operability determination allowed circumventing the commitment. On June 13,1997, the licensee submitted a letter to the NRC revising the wording and clarifying the intent of this commitment.
c.4 Conclusions Changes made to the IST program document did not strictly support the original WE commitment wording. The licensee subsequently revised the commitment to
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correspond to the actual changes made to the IST program document. The inspectors concluded that the licensee satisfactorily met commitment item 35 as revised, likEngineering E1 Conduct of Engineering E1.1 Qoerability Evaluations and Dearaded Eauioment Review.s a.
Insoection Scopa l
The inspectors reviewed operabikty evaluations supporting CRs associated with degraded equipment and evaluated the licensee's actions for resolving degraded equipment issues. Due to commitment item similarities, the following items were reviewed together:
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WE Commitment Item 20: " Review items from existing open item lists (e.g., NUTRK) to identify potentially degraded equipment."
WE Commitment item 22: "All open operability evaluations for Unit 2 and common equipment will be reviewed for acceptable closure of the degraded equipment issue.
Disposition outstanding issues in accordance with 10 CFR 50.59 and Generic Letter 91-18." This commitment was subsequently changed to "All open condition reports for Unit 2 and common equipment will be evaluated for their impact on unit restart. Any equipment operability concems will either be corrected or evaluated for operability for continued operation in accordance with our Operability Determination procedure and
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Generic Letter 91-18, Equipment which is operable but either degraded or nonconforming will be identified and tracked within our corrective action program to ensure timely correction of these issues."
b.1 Observations and Findinos The licensee utilized an independent contractor to review all open NUTRK items (2384).
The inspectors reviewed the draft interim findings of this ongoing review dated June 4, 1997. This review recommended resolution of 49 Unit 2 degraded equipment issues identified in CRs, Engineering Work Requests, and Licensee Event Reports before Unit 2 restart to meet commitment item 20. An additional 40 issues were identified as needing actions to resolve potential operability concerns before Unit 2 restart to meet commitment item 22. In parallel with the contractor reviews, the licensee established a System Engineering Review Board (SERB) and Outage Review Committee (ORC) to review 70 systems including the risk significant ones. The reviews identified degraded equipment and system operability concerns. As of June 4,1997,518 items were identified as needing resolution before Unit 2 restart. A licensee comparison of items identified by the contractor and the SERB resulted in 16 additional items that were identified by the contractor. The licensee was assessing the difference between the SERB and contractor numbers. The results were not available for review by the inspection end date.
The inspectors independently reviewed a list of outstanding items (opened since 1996)
in NUTRK's for the steam generator (SG) and reactor coolant (RC) systems. No
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O additional Unit 2 degraded equipment items were identified. However, the inspectors noted in CR 97-0630 that Unit 1 SG blowdown isolation valve 1MS 2045 had been found frozen in February 1997 The corrective actions did not fully address whether the pipe and valve design limits had been exceeded. The inspectors questioned the licensee as to the potential for damage to 1MS 2045 and piping from the inadvertent freezing. This prompted the licensee to assign a corrective action item to inspect the valve and piping. Work order No.114219 was subsequently issued to initiate the inspection and/or repairs to this non-safety valve. Licensee staff indicated that the valve would be inspected / repaired before Unit 1 restart.
The licenseo revised commitment item 22 in their letter to the NRC dated June 13, 1997. The revised commitment more accurately defined the licensee's planned corrective actions for this commitment. All open CRs involving operability concerns were now reviewed by the SER3 and ORC groups. Equipment which were operable but degraded or nonconforming were identified and tracked in the corrective action system to ensure timely resolution of the issues,
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c.1 Conclusions The licensee implemented dedicated review groups consisting of system engineers and managers to ensure degraded equipment issues were identified and resolved before
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Unit 2 restart. The inspectors reviewed the operability determinations identified in Attachment A of this report and concluded that the licensee satisfactorily met commitment items 20 and 22 for Unit 2. However, the inspectors identified one potential j
degraded equipment issue for Unit 1. The inspectors concluded that less rigor had been i
applied in resolving the Unit 1 frozen valve issue than was being applied to Unit 2 issues, b.2 Promot Ooerability Determination - CR 97-0606: G03 Voltaae Monitorino Relav Calibration The G03 voltage monitoring relay was recently calibrated on May 22,1997, during the performance of routine maintenance procedure 9043-31, " Emergency Diesel Generator G03 2 Year Electrical Inspection." The rs-found relay setting was 3990 volts. This value exceeded the low voltage tolerance band of 4007.5 volts. Relay personnel reset the relay within tolerance at 4011 volts. However, the inspectors identified that a CR had not been issued to evaluate potential EDG in-operability at the as-found value.
Procedure NP 5.3.1, " Condition Reporting System," stated, in part, that a condition report was a method to identify and to evaluate a condition which had the potential to adversely affect equipment operability, such as discrepancies associated with alarms, setpoints, and calibrations. The failure to follow procedure NP 5.3.1 is a violation (50-266/97010-02(DRS); 50-301/97010-02(DRS)) of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," which states that activities affecting quality shall be accomplished in accordance with the applicable procedure.
In response, the licensee issued CR 97-1779 to evaluate this concem and provided the inspectors calculation No. N-94-095, "Setpoint for G03/G04 Voltage Monitoring Relay."
The inspectors determined that the minimum bus analytical operating voltage was 3931 volts. Since this value was lower than the as-found relay setting, the inspectors
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determined that the G03 emergency diesel generator was capable of performing its safety function.
c.2 CDDClullOQ1 The inspectors concluded that licensee personnel failed to identify that setpo!nt drift could create a situation where equipment may have become potentially inoperable. The inspectors identified a violation for not writing a condition report to address emergency diesel generator operability when ths voltage monitoring relay was found out of-calibration.
E1.2 Review of 10 CFR 5.0.59 Screenings and Safetv Evaluations a.
Insoection Scoce The inspectors reviewed past 10 CFR 50.59 screenings, and safety evaluations
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performed during the current outage. The reviews were performed to ensure screening questions were accurately answered to determine if full safety evaluations were required. In addition, current outage safety evaluations were reviewed to assest the
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licensee's ability to identify unreviewed safety questions.
b.
Observations and Findings b.1 WE Commitment item it: ' Review 50.59 screenings conductedin 1996. Upgrade those determined to require a 50.59 evaluation."
The licensee evaluated safety evaluation screenings performed during 1996 for accuracy and compliance with requirements. The results were documented in QA Audit No. A-P-96-17. Out of 200 screenings reviewed, six were identified as regairing a full safety evaluation and six were identified as being questionable.- None of the upgraded screenings identified a potential unreviewed safety question, An independent review performed by a contractor concurred with the licensee's results.
The licensee identified several improvements in the screening process, such as
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procedure improvements to clearly define what constitutes a screening, and to ensure that screenings performed by different groups will include the same content, style and scope of information in the screenings.
c.1 Conclusions The inspectors reviewed the safety evaluation screenings identified in Attachment B of this report and determined that they adequately determined if a full safety evaluation was required. ' The inspectors concluded that the licensee satisfactorily met commitment l tem 17.
b.2 WE Commitment Item 19: ' Review 50.59 safety evaluations performed this outage.
Ensure all conditions of the evaluations have been completed."
The licensee independently reviewed the 10 CFR 50.59 safety evaluations performed for the current U2R22 outage. This review examined whether the safety evaluations
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I were accurate and met procedure requirements and that all conditions described in the evaluations were completed. Out of forty six safety evaluations reviewed, six were
. identified to have issues that required resolution prio' 3 i Unit 2 restart. These issues were added to the Unit 2 restart commitment spread sheet.
L c.2 Conclusions
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The inspectors reviewed the safety evaluations identified in Attachment B of this report
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b.3 WE Commitatent item 29: ' Complete a 50.59 safety evaluation for the existing CCW
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supply to the RCP seals as e safety-related function." This commitment was withdrawn in a letter dated June 13,1997.
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The licensee originctly committed to the NRC in letters dated December 21,1992, and June 17,1993, to upgrade the CCW supply to the RCP seals as a safety related
function. As a restart issue, the licensee indicated that they would perform a safety evaluation to address the upgrade. However, the licensee did not complete the safety evaluation. The licensee's engineering staff had concluded that it was not practical nor a significant improvement in safety to upgrade the CCW supply to the RCP thermal barriers to meet single failure criteria. This was based, in part, on the plants original design criteria indicating that there existed inherent strengths in the original RCP seal design, that there have been RCP seal design improvements, and tr.at similar vintage
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and designed pressurized water reactor facilities also consider this system 'o be non-safety. The licensee intended to re'ract this commitment. A formal commitment retraction letter was sent to the NR O Region lli on June 13,1997.
c.3 Conclusions The licensee has withdrawn their commitmt nt to perform a safcty evaluation for the CCW supply to the RCP seals.
b.4 WE Corr ment item 31: " Evaluate the ariequacy of coordination on the 120 VAC instrumens bus system through a 50.59 or operability review."
Each safety related 120 Vac instrument bus supplies non-safety loads. This was part of Point Beach's original design. Since these loads were classified as non-safety, their power cables were not physically separated. Electrical protection was provided by molded case circuit breakers (MCCBs).- However, the non-safety MCCBs did not electrically coordinate with the safety related instrument bus static inverter supply breakers. This occurred at the inverter current limit value. The potential existed, due to inadequate cable separation, for more than one instrument bus to be loss due to a common failure of two non-safety cables. The loss of two instrument buses would cause their associated reactor protection and safeguards channels to fail in a tripped condition. ; Even though the reactor would trip and safety injection could be initiated, the potential existed for both units bus specific safety injection loads to be loaded on their associated EDG if offsite power was loss. This could overload the engines if the units
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l were aligned to share tw'o EDGs (original design). However, with the addition of two extra safety related EDGs, two EDGs were normally aligned to each unit.
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The licensee laentified that the original prompt operability determination performed in
December 1996 was inaccurate. This determination was based on an available fault current that would not exceed the inverter current limit. As a result of the review, the licensee determined in January 1997 that the calculated cable impedances were non.
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conservative. This increased the available fault above the inverter current limit.
i Modification MR 97-005, " Install Conduits and Cables to Resupply 2Y11,2Y21,2Y31, and 2Y41," was implemented to correct this deficiency. The modification installed cables that re-powered electrical panels 2Y11,2Y21,2Y31 and 2Y41 from non-safety power sources. The inspectors reviewed SER 97-025 approved for the modification and determined that the changes to the facility did not create an unreviewed safety question.
c4 Conclusions
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Even though the licensee adequately resolved this deficiency, the inspectors were
concerned that the original prompt operability determination was based on a non-conservative analysis. The licensee has taken steps to improve their review and
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resolution of conditions adverse to quality. This was noted by the inspectors during condition report reviews, safety evaluation reviews and other prompt operability i
determination reviews. The inspectors concluded that the licensee satisfactorily met
commitment item 31.
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b.5 WE Commitment item 33: " Implement interim improvements for the 50.59 process to
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require that all screenings be either authored or reviewed by a member of the multi-
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disciplinary review team."
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The licensee implemented interim improvements in the safety evaluation process and
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required that all screenings be either authored or reviewed by a member of the multi-disciplinary review team. Procedure NP 10.3.1, " Authorization of Changes, Tests, and
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Experiments (10 CFR 50.59 and 72.48 Reviews)," dated February 14,1997, was l
revised to requiro a member of the multi-disciplinary review team to review and sign the
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st,reening, The licensee initiated training of individuals that could be in-line for reviewing l
and approving screenings, in addition, procedure NP 10.3.1 was completely rewritten and approved on May 30,1997, to improve the safety evaluation process. Plant staff
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t involved with safety evaluations were retrained on the new procedure. 'A list was -
created that detailed which individuals 'Nere qualified to review and approve screenings
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and safety evaluations.
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l The inspectors reviewed a sample of the screenings performed during 1996 (Item 17)
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and safety evaluations performed for the current Unit 2 refueling outage (Item 19) and determined that qualified individuals had reviewed and approved the evaluations.
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c.5 Conclusions
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j The inspectors determined that some improvement in the 50.59 process had occurred.
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The inspectors concluded that the licensee satisfactorily met commitment Item 33.
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E1.3 WE Commitment item 21: * Review open items from the Design Basis Document development program.'
a.
10$ncetion Scope The inspectors evaluated the corrective actions for resolving Design Basis Document open items (DBDOI). The following iterns were reviewed:
DBDOI 22-004 (Closed March 11,1997)- Minimum setting for the reactor trip on undervoltage could not be verified.
DBDOI 30-004 (Open January 3,1996)- Containment fan cooler start time is greater than Final Safety Analysis Report (FSAR) assumptions.
DBDOI 33 002 (Open January 6,1996)- Bechtel calculations do not appear to address seismic loads from internal containment structures.
DBDOI 35-004 (Open February 5,1997) - Explain why a feedwater line rupture is not a design basis event for Point Beach, b.
Observations and Findings An outside contractor reviewed approximately one half of the open DBD items and determined that none of the items would affect Unit 2 restart. The following is a
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summary of the documents reviewed by the inspectors:
N DBDOI 22-004 was reviewed during a previous inspection and resulted i a o
violation (50-266/96018-07n(DRS); 50-301/96018-07n(DRS)). The licensee's response letter, dated April 2,1997, provided the NRC with their proposed corrective actions for the violation. The letter stated,"The 90 millisecond bounding value in the calculation does not bound the maximum limit established in the current version of RMP-26 (10 cycles or 167 milliseconds), but it does bound all known historical test data." However, the inspectors identified a March 17,1984, Unit 1 "B" reactor trip bypass breaker opening time that equaled 100 milliseconds. The licensee submitted a letter to the NRC on June 11,1997, correcting and clarifying their previous response. In addition, the inspectors requested that the licensee provide the evaluation supporting the statement that the 90 millisecond breaker opening time was an appropriate calculation input from a statistical viewpoint. The licensee was unable to provide an evaluation at the conclusion of the inspection to support this statement. Pending NRC review of the licensee's resolution of this issue, violation 50-266/96018-07n(DRS); 50-301/96018-07n(DRS) will remain open.
DBDOI 30-004 operability assessment was documented in CR 96-1486. The o
licensee concluded in this CR and supporting calculation No. 97-0041, Revision 0, that the containment fan cooler delayed loss of accident coolant (LOCA)
starting time was beyond the 60 seconds assumed in the FSAR. However, this only slightly increased the pressure and temperature profiles expected during a LOCA. In addition, this had minimal affect on safety related equipment located inside containment since the increased environmental conditions were bounded
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by the equipment qualification profiles. FSAR change request FCR 97-25 was initiated to clarify the actual time delay expected for starting the containment fan cooler.
DBDOI 33-002 qu"-tioned the seismic design of containment. The licensee o
performed calculation Mo. 10447 9611-001, Revision 0, to demonstrate that containment was seismically designed. The inspectors determined that the calculation addressed the seismic issues.
DBDOI 35-004 evaluation was completed on February 5,1997. The licensee o
concluded that a feedwater line break was not a design basis accident for Point Beach. This evaluation referenced proprietary Westinghouse letter PBW-B-200,
" Missile Protection Criterion," dated May 2,1967, which evaluated the affects of a feedwater line break as a potential missile source. In addition, the licensee's response to IE Bulletin 79-21, dated September 9,1979, also evaluated the affects of high energy line breaks on safety related instrumentation. The
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inspectors reviewed the referenced documents and the accidents described in FSAR Chapter 14, and determined that the feedwater line break accident was not a Point Beach design basis accident, This DBD item remained open pending licensee clarification of a module in their accident analysis (DBD T 35) to support DBDOI 35-004 closure. The inspectors considered this action adequate to address this item.
The inspectors reviewed CRs written in 1997 to address DBDOls and recent changes to DBD program procedures NP 7.7.3,"As-Built Drawing Program and Design Basis Document Program Open item Management," Revision 1, and DBDP-43, "PBNP DBD
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Program Procedures Design Basis Open item Management," Revision 3. Changes incorporated into these procedures included: that non-editorial DBDOls now required SRO and System Engineer evaluations for impact on system operability before issui1g the DBD; requirements for prioritizing DBDOls for timely resolution based on safety ad risk significance; and that DBDOls were reviewed on a semi annual basis to verify that their priority and status had not changed. These changes appeared to add the necessary programmatic guidance to ensure that DBDOls were dispositioned in a timely manner and received a prompt operability determination, if applicable.
c.
Conclusions Recently implemented changes in the DBD program appeared to add programmatic guidance to evaluate and timely disposition DBDOls which had potentia' system operability impact. The inspectors concluded that the licensee satisfactorily met commitment item 21.
E1.4 FSAR Reviews a.
Insoection Scoce inspectors reviewed the following FSAR sections:
FSAR Section 5.3 - Containment Ventilation System o
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FSAR Section 5.6.2.1 - Corrosion of Metals of Construction in Design Basis -
o Emergency Core Cooling Solution b.
Observations and Findings The inspectors identified inconsistencies in the FSAR section associated with the amount of hydrogen produced from galvanized steel following a LOCA. Point Beach FSAR Section 5.6.2.1 appeared to incorrectly use a 0.003 mil / month corrosion rate for galvanized steel. A 0.051 mil / month corrosion rate was previously used for galvanized steelin a 200*F borated solution. The inspectors were concemed that the potential impact from post-LOCA hydrogen generation may have been underestimated by 17 fold.
This was due to increased galvanized steel corrosion rates in the post-LOCA containment environment. The galvanized steelinside containment could see temperatures > 200'F for approximately eleven hours. Calculation No. 97110 was
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initiated and the preliminary results indicated that approximately 20 percent of the total (
l-post-LOCA hydrogen production would be attributed to corroding galvanized steel and
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i zinc based primers. Therefore, FSAR Section 5.6.2.1 conclusion that the contribution to
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the total hydrogen produced from galvanized steel was insignificant appeared to be incorrect. However, the additional hydrogen contribution from the corrosion products did no. increase total post-LOCA hydrogen generation above the 4.1 percent FSAR flammability limit. The licensee indicated that an FSAR change would be initiated to correct Section 5.6.2.1. Since the inspectors did not review an approved version of calculation No.97-110, this is considered an inspection followup item 50-266/97010-03(DRS); 50-301/97010-03(DRS) pending NRC review of ths approved calculation, c.
Conclusions The inspectors concluded that the identified FSAR statement error did not affect equipment operability or change any previously analyzed conditions.
E2 Engineering Support of Facilities and Equipment E2.1 Control Room Emergencv Filtration (CREF) System a.
Insoection Scoce The control room ventilation system was reviewed to determine if the CREF system could perform its intended safety function. This review included examining design assumptions, boundary conditions, models, calculations and procedure TS-9, " Control Room Heating and Ventilation System Monthly Checks."
b.
Observations and Findinas The inspectors walked down the CREF system using piping and instrumentation diagram M-144. During the walkdown, the inspectors noted that the computer room supply and exhaust dampers (control valves 4849A and 4849B) failed closed during a loss of instrument air or a loss of offsite power (LOOP). According to emergency operating procedure 0, Appendix C, " Control Room Ventilation Recirculation Modes,"
the CREF dampers should be open for emergency Mode 4 operaSon. The inspectors
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were informed that the damper's failure to the closed position was required to allow proper operation of the computer room Halon fire suppression system. During a LOOP, the control room envelope volume would be reduced from 65,243 ft* to 40,529 ft for
about one hour due to the loss of power to the CREF system. The licensee indicated that both the CREF fans and instrument air system would be manually loaded on an EDG within one hour following a large break LOCA concurrent with a LOOP Following re-powering of tne CREF system EOP-0 required the operators to verify proper system (Mode 4) alignment. With the instrument air system powered by an EDG, the operators could reposition the dampers from inside the control room, The CREF system has 14 charcoal filter trays each rated at 333 cfm for a total capacity of 4662 cfm. The charcoal tray design is based on a face velocity of 40 ft/ min, However, the inspectors were concemed that the charcoal may actually be exposed to air at a face velocity greater than 40 ft/ min when operated at the 4950 * 10% cfm TS system flow rate. The licensee performed a calculation to determine the actual face velocity that the installed charcoal was exposed to by using the actual as built charcoal
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filter tray dimensions. Using the system flow rate of 4950 cfm, the licensee calculated a face velocity of 40.8 ft/ min. In addition, the licensee referred the inspectors to the 22d DOE /NRC Nuclear Air Cleaning and Treatment Conference paper, " Parametric Studies of Radioactive lodine, Hydrogen lodide and Methyl lodide Removal," by J. L. Kovach,
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which discussed the effects air velocity had on charcoal methyl lodine penetration.
Using the curve from the paper which plots methyllodide penetration as a function of air velocity, the licensee determined that the lodine removal efficiencies were not greatly i
affected by the differences in the air flow rates including measurement tolerances. The inspectors performed an independent evaluation using Equation 1 in Section 9 of American Society for Testing and Materials (ASTM) D3803-1989, " Standard Test Method for Nuclear-Grade Activated Carbon," and obtained similar results. The inspectors determined that the charcoal filter trays were adequately designed to handle the TS flow rate.
Differential pressure of the control room envelope (control room and computer room)
with respect to adjacent areas (turbine building, auxiliary building, cable spreading room, and the mechanical equipment room) were measured by the system engineer while the CREF was operating in emergency Mode 4. The control room envelope was always positive (2 0.125 inches of water column (INWC)) with respect to the adjacent areas.
However, at times the control room envelope with respect to the cable spreading room dipped to < 0.125 INWC. The TSs had no requirements for performing a positive -
pressure test in the control room. The only requirement for performing the emergency mode test was in Section 1.1 of TS-9 which required the control room pressure to be maintained 2 0.125 INWC differential pressure (dP) with respect to the turbine building.
The inspectors pointed out that to measure the dP between the control room and only one adjacent area did not verify if other adjacent areas had excessive leakage. To be consistent with the safety function of the CREF system, the dP of the whole control room envelope should be measured with respect to all adjacent areas to ensure that the unfiltered in-leakage was less than that assumed in the dose analysis. The licensee acknowledged the inspectors observation.
The inspectors noted that two control room doors did not have door seals. This increased the outward air leakage when the ventilation system was in Mode 4 lowering the control room dP at these doors. The addition of the seals would help increase the
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O pressure in the control room and thus increase the pressure difference with respect to the cable spreading room. However, the licensee indicated that they had considered putting seals on the doors, but determined that they would not be able to open the control room doors when the smoke removal system was running. To address the dP issue, the licensee initiated CR 971676 to determine if the control room envelope should be maintained at > 0.125 INWC positive pressure with respect to all adjacent areas during emergency mode operation.
The inspectors reviewed the TSs required surveillance tests for the charcoal and high efficiency particulate absolute (HEPA) filters. Test results for the past two years met TS acceptance criteria.
The inspectors discussed with the shift supervisor the use of Potassam lodide (KI)
tablets during an accident. The supervisor indicated that the decision to use Kl tablets was made by the Health Physics group. The inspectors reviewed Emergency Plan Imolementing Procedure EPIP 5.2,"Radiolodine Blocking and Thyroid Dose
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Accounting." In the event of an emergency, this procedure instructs Health Physics to administer K1 to authorized personnelif the calculated projected dose to the thyroid was likely to exceed 25 rem. If the projected dose was to be < 25 rem, then issuance of KI was at the discretion of the Health Physics director or the rad / con waste manager. A list was maintained of all employees authorized to take K1 tablets. Approximately 80 vials (14 tablets each) with an expiration date of May 2000 were maintained in the control room. The instructions stated that adults should take one tablet, once per day. The inspectors concluded there was an adequate supply of Kl tablets in the control room, c.
Conclusions The licensee committed in a letter dated March 5,1997, to meet 10 CFR 50, Appendix A, General Design Criteria 19 dose limits without the use of Kl tablets or supplied breathing air. The new dose analysis was to be submitted as a license amendment by February 28,1998. In addition, the licensee committed in a letter dated June 13,1997, to increase the test frequency of the CREF charcoal and HEPA filters from once per year (TS 15.4.11) to once every six months. The increased testing frequency provides additional assurance that the charcoal was capable of performing at a level at least as good as that assumed in the licensee's dose analysis. Based on these commitments and the inspection observations, the inspectors concluded that the CREF system was capable of performing its safety function.
E2.3 WE Commitment item 59' ' Modification 96-070 rep l ace molded case circuit breakers associated with instrument buses 2Y-06 and 2Y-06.~
a.
Insoection Scops The inspectors reviewed modification No.96-070. This modification replaced instrument buses 2Y-05 and 2Y-06120 Vac molded case circuit breakers (MCCBs). In addition.
the inspectors reviewed other licensee actions associated with DC MCCBs.
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b.
Observations and Findinos The licensee identified a condition where six circuits in non-safety related 120 Vac Instrument panels 2Y-05 and 2Y-06 did not have correctly sized breakers. The breakers did not provide adequate short circuit protection for internal main control board wiring.
The existing breakers had 30 ampere trip ratings with the exception of one Unit 2 circuit which had a 40 ampere trip rating. This would not protect No.14 AWG wiring. Not clearing a fault had the potential to damage the conductor but also damage adjacent safety related circuits. In addition, due to a lack of electrical train separation in the main control boards, the potential existed to damage redundant train wiring. In response, modification No.96-070 replaced the existing circuit breakers with ones having a lower trip rating (20 amperes).
The licensee identified that original equipment MCCBs were vulnerable to higher than predicted age related failures of the instantaneous (magnetic region) trip device while still providing overload protection (thermal region). The licensee replaced all of the
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alternatirg currents (AC) breakers. However, only selected DC breakers were replaced.
Twenty three breakers were scheduled for replacement before Unit 2 startup. Those chosen for immediate replacement were the safety related breakers supplying non-safety loads. This breaker replacement prioritization significantly reduced the chance that a non-safety load or cable would cause a loss of safety function. The licensee
planned to replace all DC MCCBs by the end of the next refueling outage.
If plant conditions permitted, the licensee indicated that non-replaced Unit 2 DC MCCBs would be cycled before startup to exercise the operating mechanism. However, the cycling would not exercise the trip mechanism. Newer style MCCBs were provided with a trip push button that would exercise the breaker trip and operating mechanism.
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Conclusions The inspectors concluded that the licensee adequately addressed MCCB tripping issues and the lack of coordination. The inspectors further concluded that licensee evaluations by applicable electrical computer programs; such as, CAPTOR - for electrical coordination, CARDS - for cable routing, and DC ELF - for maximum de short circuit current, provided reasonable assurances that hypothesized DC breaker failure modes had been appropriately analyzed. The inspectors concluded that the licensee satisfactorily met commitment item 59.
E2.4 WE Commitment item 28: " Resolve the containment penetration commitments, including:
CP-32 (Containment penetration for Auxiliary Charging line).
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Penetration thermal reliefissue."
a.
Insoection Scoce The licensee initiated eleven actions in response to Generic Letter 96-06, " Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident." These actions included completed or scheduled piping modifications at containment penetrations CP-11, CP-28b, CP-12a and CP-53 for both Units. In addition, the
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inspectors reviewed modification Nos. MR 96-057B and MR 96-057D (in progress for Unit 2) to evaluate the licensee's corrective actions for penetration CP 32 thermal relief issues.
b.
Observations and Findings The licensee implemented Unit 2 modifications MR 96-0578 and MR 96-057D to containment penetration CP 11 (seal water return line) and CP-28b (pressurizer liquid sample line) piping. This was to prevent penetration over-pressurization during a LOCA due to trapped fluid heat-up between containment isolation valves. The inspectors reviewed condition reports, calculations and operability determinations associated with these modifications and for other penetrations that were susceptible to this phenomenon. Calculation input assumptions were conservative and provided a reasonable technical basis to support engineering staff conclusions. The licensee planned the Unit 1 modifications for the next refueling outage. The inspectors determined that the corrective actions completed or in progress were thorough and
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consistent with GL 96-06 commitments.
On November 23,1996, the licensee discovered pressurized water in Unit 2 containment penetration CP-32. This penetration was normally dry. The licensee drained an estimated 20 gallons of water. Subsequent investigations determined that the source of water was a 0.75 inch long radial crack in the containment weld heat affected zone of a safety injection and auxiliary charging line. The licensee determined that a contributing factor for this crack may have been a partial penetration weld made during original construction. The licensee replaced the failed safety injection and
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auxiliary charging line pipe at this penetration. Post modification testing included visual l
inspections and leak testing, in addition, the licensee inspected similar containment penetrations for the presence of water and found no other leaking pipes. The inspectors determined that the corrective actions adequately demonstrated CP-32 containment penetration integrity.
c.
Conclusions The licensee identified containment penetration piping systems that were susceptible to thermally induced over-pressurization during LOCA conditions. For these systems, the licensee implemented or scheduled modifications to resolve this issue. The inspectors concluded that the licensee satisfactorily met commitment item 28.
E2.5 Accendix R lss.ugs a.
Insoection Scoce The inspectors evaluated work order Nos. 9513222 through 9513225 that were used to inspect Appendix R alternate power transfer switches associated with WE commitment item 5. In addition, the inspectors reviewed the following Ucensee Event Reports (LERs):
LER 97-020 Conditions Outside 10 CFR 50, Appendix R Safe Shutdown Analysis
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LER 97-022 Electrical Short Circuits During A Control Room Fire Could Affect Safe Shutdown Capability LER 97-023 Noncompliant Emergency Lighting For Postulated Appendix R Fires b.
Observations and Findings b.1 WE Commitment item 5: " Complete Work Orders 9513222 through 9513225 to conduct inspections of Appendix R attemale power transfer switches. "
The licensee took apart the ASCO transfer switches to venfy whether an "E" shaped retaining ring located on the arcing contacts was in place. In all cases, the "E" ring was I
properly installed, in addition, the inspectors determined that post-maintenance testing of the re-assembled switches had been performed in an acceptable manner, tA2 LER 97020 On April 14,1997, with Unit 1 in cold shutdown and Unit 2 in a defueled condition, the licensee identified six previously unreported conditions during their review of open Fire Protection Program CRs. The following CRs should have been reported:
(1) CR 96 553 Re-entry into Cable Spreading Room (CSR)
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A review of the Appendix R Safe Shutdown Analysis indicated that manual operation of breakers may be required during a postulated fire in the CSR, requiring entry into the fire area.
Licensee corrective actions included the modification of the G05 (gas turbine) control circuits to provide local / remote isolation for a fire in the CSR. This will provide the capability to re-power the "B" charging pump transfer switch without entering the fire l
area. In addition, appropriate procedures will be written or revised. This modification will be completed before Unit 2 startup.
(2) CR 96-136 Inadequate Breaker Coordination Causes Yellow Instrument Bus Loss Electrical cable routing reviews identified a 125 Vdc power cable that should not have been routed through the North Zone of the auxiliary feedwater (AFW) pump room. A fire induced fault on the cable, due to the lack of selective breaker coordination, could result in the loss of 125 Vdc bus D04 which supplies power to the " yellow" instrument channels.
Licensee corrective actions included the installation of a 1-hour firewrap on conduit D04-7. This modification will be completed before Unit 2 startup.
(3) CR 96-889 Inadequate Coordination May Disable all Emergency Power The normal 125 Vdc power feeds to the G02 EDG were re-powered from distribution panel D31 during the EDG addition project. The G02 power cables were routed through
the North Zone of the AFW pump room. The G02 EDG was the Appendix R power j
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source for a fire in this zone. However, the G02125 Vdc power feeds were not protected from fire (wrapped) and the other three EDG power cables were also routed through this area. A fire induced fault on the G02 control power cable, due to the lack of selective breaker coordination, could result in the loss of G02. In addit!on, the other three EDGs could be lost for a fire in the North Zone of the AFW pump room.
Licensee corrective actions included the installation of a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> firewrap on conduit D04-7. This modification will be completed before Unit 2 startup. In addition, this will restore G02 capability for a fire in the AFW North fire zone.
(4) CR 94 328 Unanalyzed Procedural Guidance for EDG Loading (G01/G02)
A review of Appendix R safe shutdown procedure AOP-10A, " Safe Shutdown - Local Control," identified that G01 or G02 would be started with their output breaker closed along with already closed 480 volt essential load breakers. No analysis existed to demonstrate the capability of the G01/G02 EDGs to reach rated speed and flash their
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field with connected loads.
Licensee corrective actions included revising the safe shutdown procedures to use G03 or G04 EDGs before Unit 2 startup. The G03 or G04 EDG could be started with their output breaker open.
(5) CR 92 372 Lack of Ventilation Analysis for Safe Shutdown Equipment A review of the original Appendix R Safe Shutdown Analysis indicated that certain ventilation equipment were not listed on the Appendix R essential equipment list as equipment necessary to achieve safe shutdown. The original analysis did not address the electrical effects of fires on ventilation electrical circuits and did not evaluate safe
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shutdown equipment operability for the potential loss of cooling.
Licensee corrective actions included the procurement of portable fans and the development of procedures for their deployment before Unit 2 startup. Per NUTRK ltem LER 266/97-020-00, the licensee committed to functionally test the deployment of the fans for Unit 2 by October 31,1997.
(6) CR 96 959 Inadequate Procedural Guidance of Bus Stripping The licensee's review of Appendix R safe shutdown procedures AOP-10A and AOP-10C identified that the operators were directed to the wrong DC electrical panel for isolating control power to 4 KV switchgear 2A05 and 480 volt bus 2B03.
Licensee corrective actions included revising the AOPs before Unit 2 startup.
The licensee's staff identified that the initial root cause for not identifying these items as outside their design basis was due to Appendix R requirements not being included in FSAR Chapter 14 analyses. Based on that interpretation, the identified Appendix R conditions were not considered to be "outside the design basis" pursuant to 10 CFR 50.72 and 50.73. However, the licensee concluded that the root cause relative to the six CRs was attributed to shortcomings in the documentation or implementation of the existing Appendix R Safe Shutdown Analysis.
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The above examples collectively represent a significant break down in engineering staff's evaluation of Appendix R issues at Point Beach. The safety consequencet, are significant in that safe shutdown of a unit in response to a fire and a loss of offsite power may not have been obtainable. These examples violate multiple Appendix R requirements. Only CR 96-553 appeared to meet certain approved exemptions of Appendix R requirements. A horizontal distance of approximately 20 feet existed between the fire areas with minimalintervening combustibles. The cable trays that did cross between the two fire areas had fire woolin the trays and were covered. In addition, detection and suppression were located throughout the common room. The remaining CRs address conditions that could have prevented the recovery from a fire.
Appendix R, Section ill.G.2, requires, in part, where cables that could prevent operation or cause maloperation due to hot shorts, or shorts to ground, of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area, a means to ensure one of the redundant trains is free of fire damage shall be provided.
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The following are examples of an apparent violation (50-266/97010-04(DRS);
50 301/97010-04(DRS)) of 10 CFR 50, Appendix R, Section Ill.G.2, requirements:
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The licensee failed to identity during the original Appendix R reviews the lack of 125 Vdc circuit breaker electrical coordination as described in CR 96136. The cables routed through conduit D04 7 were susceptible to fire induced shorts for a fire in the North auxiliary feedwater area. This had the potential to cause the
" yellow" instrument channels to be loss. The " yellow" instruments were the redundant train of safe shutdown components used in this fire area.
2.
The licensee failed to identify during the original Appendix R reviews the lack of 125 Vdc circuit breaker electrical coordination as described in CR 96-889. The cables routed through conduit D04-7 were susceptible to fire induced shorts for a fire in the North auxiliary feedwater area. This had the potential to cause the loss of all EDGs. The G02 EDG was the analyzed redundant train of safe shutdown equipment used in this fire area.
Appendix R Section Ill.L.1, requires, in part, that attemative or dedicated shutdown capa' ility provided for a specific fire area be able to (a) achieve and maintain subcritical o
reactivity conditions in the reactor; (b) maintain reactor inventory; (c) achieve and maintain hot standby conditions; (d) achieve cold shutdown conditions within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; and (e) maintain cold shutdown conditions thereafter.
The following are examples of an apparent violation (50-266/97010-05(DRS);
50-301/97010-05(DRS)) of 10 CFR 50, Appendix R, Section Ill.L1, requirements:
1.
The licensee failed to identify during the original Appendix R reviews that the original safe shutdown analysis did not adequately document the capability of the G01/G02 EDGs to start and flash their fields with their output breaker closed and 480 volt loads connected to the EDG bus as described in CR 94-328. The potential existed for the altemative shutdown path, use of the G01 or G02 EDG, to be loss leaving no success path for safe shutdown.
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The licensee failed to ldentify during the original Appendix R reviews that the original safe shutdown analysis did not adequately document the ventilation
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requirements for certain safe shutdown equipment as described in CR 96 372.
The potential existed for altemative safe shutdown equipment to be loss due to the lack of room cooling.
The following example is an apparent violation (50 266/97010-06(DRS);
50 301/97010-06(DRS)) of Appendix B, Criterion V requirements that procedures contain appropriate qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. The licensee falle"1 to provide adequate bus stripping procedure guidance as described in CR 96459. Post fire safe shutdown Abnormal Operating Procedures (AOPs) 10A and 10C directed the operators to the wrong DC power panel (D11). Isolating the wrong power supplies had the potential to cause spurious operation of equipment powered from buses 2A05 and 2B03 during a fire.
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b.3 LER 97022 On May 7,1997, with Unit i in cold shutdown and Unit 2 in a defueled condition, the j
licensee's Appendix R rebaselining team disccvered that a postulated Control Room fire
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may cause an electrical" hot short" that bypasses the limit switch or torque switch for certain motor-operated valves (MOVs) that wero essential for achieving an Appendix R safe shutdown condition. Spurious operation of an MOV with a bypassed limit or torque switch could cause a valve operator to generate thrust and torque values which exceed the design limits of the valve. The resultant physical damage to the valve may preclude I
manual manipulation of the valve for a Sre that required Control Room evacuation.
Fifteen MOVs (total for both units) were identified as being susceptible to " hot shorts."
The licensee modified the fifteen valves to prevent a " hot short" from causing mechanical damage, The licensee concluded that the non-Intuitive nature of the failure mode described by information Notice 9218, * hot shorts" which bypass torque switch / limit switch protection, were never considered in the original Appendix R safe shutdown analysis, The licensee's information Notice 9218 review that was approved on April 5,19fs3, concluded the MOVs were protected by their motor thermal overload (tot.). A missed opportunity existed since the licensee did not recognize that valve failure may eccur before the motor TOL opened. A weak link analysis was not performed which would have identified the valves that could suffer mechanical damage before removing power from the valves.
The above example represents a significant break down in engineering's evaluation of Appendix R issues at Point Beach. The safety consequences are significant in that safe shutdown of a Unit in response to a fire and a loss of offsite power may not be obtainable. However, the " hot short" issue is currently under review by the Office of Nuclear Reactor Regulation (NRR). The NRC is evaluating the * hot short" issue as having generic Industry implications. Therefore, unresolved item (URI)
50-266/96018-21(DRS); 50 301/96018 21(DRS) which originally addressed this issue, will remain open pending further NRC review.
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bA LER 97023 On May 8,1997, with Unit i in cold shutdown and Unit 2 in a defueled condition, the licensee's Appendi.v R rebacelining team identified that certain plant areas lacked adequate emergency lighting. This discovery was made during a review of post fire emergency lighting requirements. As described in the Point Beach Appendix R Safe Shutdown Analysis, manual actions may be required in certain exterior buildings within the protected area.
The failure to comply with the regulations occurred when alternative provisions were made in the original safe shutdc'en analysis without obta:ning a.1 appropriate regulatory exemption. Licensee actions to address these issues included installing eight hour battery powered emergency lights in the Circulating Water Pump House which houses the service water pumps and diesel fire pump before Unit 2 startup. In addition, the licensee was installing emergency lights in the vicinity of safe shutdown equipment l
etnred in Warehouse 3 (may not be completed before startup). This warehouse was
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used to stage certain Appendix R equipment, such as the portable fans.
Emergency lighting was not provided in the Circulating Water Pump House in the areas where operators had to manually start the diesel fire pump and to manually align the service water system to provide cooling water to the turbine driven AFW pump bearings.
The failure to identify that emergency lighting units were required in the Circulating Water Pump House is an apparent violation (50-266/97010-07(DRS);
50-301/97010-07(DRS)) of Appendix R, Section Ill.J which requires, in part, that emergency lighting units with at least an 8-hour battery power supply be provided in all areas needed for operation of safe shutdown equipment, c.
Concluslom The above examples represent e significant break down in the engineering staff's -
evaluation of Appendix R issues at Point Beach. The safety consequences are significant in that safe shutdown of a unit in response to a fire and a loss of offsite power may not have been obtainable. As a result, apparent violations were identified for lack of 125 Vdc coordination potentially affecting the " yellow" safe shutdown instrument channels and all emergency diesel generator, for an incomplete original safe shutdown analysis, for an inadequate safe shutdown procedure, and for inadequate safe shutdown lighting. Also, an URI will remain open conceming the " hot short' Issue, The licensee has improved in their timeliness and sensitivity in resolving and identifying conditions adverse to quality. Identified Appendix R issues were being resolved in a satisfactorily manner to support Units 1 and 2 restart. In addition, the licensee committed to perform an Appendix R Rebaselining Project. The Rebaselining Project schedule and project plan were provided to the NRC by letter, dated August 5.1997.
The inspectors concluded that the licensee satisfactorily met commitment item 5.
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E3 Engineering Procedures and Documentation E3.1 ASME Code Quahfication of the Unit 2 SG Girth Waldt a,
lamulion Scope This item concemed the ASME Codo qualification status of the Unit 2 SG girth welds.
The inspectors reviewed the following documentation related to URI 50 301/06014-02(DRS):
Wold Procedure Specification (WPS) GT SM/3.3 2 PB, Revision 1, used to o
perform the girth welds on the Unit 2 SGs.
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Procedure Qualification Record (POR) GT SM/3.3 02, Revision 0, (Documented o
the qualification weld parameters supporting weld procedure WPS GT-SM/3.3PB).
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Letter from A. J. Walcutt (Morrison Knudson Corporation) to D. Johnson i
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o (Wisconsin Electric) dated May 5,1997, which provided additional qualification information related to POR GT SM/3.3 02.
b.
Observations and Findings On November 15,1996, the inspectors identified a concern with the ASME Code (
qualification of weld procedure WPS GT SM/3.3 2 PB. This procedure was used to (
fabricate the Unit 2 replacement steam generator girth welds. The inspectors determined that the gas tungsten arc welding (GTAW) process used for the qualification weld documented in POR GT SM/3.3-02 had lower weld heat inputs (except for weld bead pass No.1) than weld heat inputs allowed (73.3 Kilo Joule per inch) by WPS GT SM/3.3 2 PB.
On May 7,1997, a phone conference was held between the licensee, the welding contractor (Steam Generator Team, Ltd (SGT)) and NRR. During this call, the welding contractor was unable to establish POR weld pass heat input values that were traceable to the Charpy impact test specimens removed from the qualification weld. However, the welding contractor reported that weld pass No.1 with a recorded weld heat input value higher than that used in WPS GT SM/3.3 2 PB would not have been included and tested along with the removed Charpy impact samples.
NRR determined that heat inputs traceable to weld material contained in the Charpy impact specimens were the heat inputs that support ASME Code,Section IX, QW 409.1, weld qualification requirements. This ensures that more limiting weld material properties created by higher weld heat inputs were measured and tested as part of the qualification weld Thus, field weld impact properties are bounded by the qualification weld and hence can be demonstrated to meet the required service condition acceptance criterion (e.g.,50 ft lbs minimum). The Charpy impact testing for qualification weld POR GT-SM/3.3-Q2 was performed with weld pass material that had lower heat inputs than allowed by WPS GT-SM/3.3 2. Therefore, the Charpy tests completed were not considered bounding.
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b The inspectors reviewed the above information and concluded that the licensee failed to meet QW-409.1 Code requirements by not qualifying WPS GT.SM/3.3 2 PB as an ASME,Section IX, weld procedure. Thus, the licensee failed to bound the weld pass heat inputs allowed by WPS GT-SM/3.3 2 PB by testing (using Charpy impact tests)
weld pass material with heat inputs from qualification weld POR GT SM/3.3-Q2.10 CFR 50, Appendix B, Criterloa IX, " Control of Special Processes," requires, in part, that measures shall be established to assure that special processes, including welding, heat treating, and nondestructive testing, ale controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, and standards. Code requirement QW 256 of Section IX,1995 Edition of the ASME Code, implemented Section QW 409.1 as a supplementary essential variable for GTAW.
Section QW 409.1 stated that "An increase in heat loput, or an increase in volume of weld metal deposited per unit length of weld, (is not allowed) over that qualified." The failure to use a Code qualified welding procedure for the Unit 2 SG girth welds is considered a violation (50 301/97010-08(DRS)) of 10 CFR 50, Appendix B, Criterion IX.
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Subsequently, the SGT contractor performed another qualification weld and additional Charpy impact testing The test results were satisfactorily completed for Code qualification of weld procedure WPS GT SM/3.3 2 PB.
c.
Conclusions The inspectors concluded that although originally the procedure was unqualified for this weld; the subsequent qualification weld and Charpy impact testing showed that the weld procedure was Code qualified.
E3.2 Emergency Diesel Generator Testing a.
Insoection Scong The inspectors reviewed the EDGs integrated load sequencing test, ORT 3. " Safety injection Actuation with Loss of Engineered Safeguards AC, Unit 2."-
b.
Observations and Findingti b,1 WE Commitment item 26: " Revise ORT 3 and DCS 3.1.11 to ensure Technical Specification 15.4.6.A.2 testing includes dynamic loading of the EDG with sequenced loads."
Procedure DCS 3.1.11 was canceled by the licensee. Past ORT 3. Revision 27, testing did not start and load onto the EDGs all of the LOCA loads identified in FSAR Section 8.2.3, " Emergency Power," page 8.2-17 (June 1996). This item was discussed in -
i inspection Report 50-266/96018(DRP); 50-301/96018(DRP), Section M3.1.1, The licensee issued ORT 3 Revision 28, on January 25,1997. This revision added the loads identified in the FSAR. The inspectors reviewed ORT 3 Revision 28, and determined that the appropriate FSAR loads would be started and sequenced onto the EDGs.
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c.1 Conclusions The inspectors concluded that the licensee satisfactorily addressed dynamic load testing of the EDGs and met commitment item 26.
6.2 WE Commitment Item 27: * Test all EDGs in accordance with revised ORT 3 and DCS 3.1.11. Retum the electrical systems to normalalignment prior to leaving cold shutdown."
Since Point Beach was in a dual unit outage, the opportunity existed to load the EDGs with the FSAR automatic sequenced LOCA loads along with the non accident unit shutdown loads. During normal plant ORT 3 testing, the operating unit shutdown loads can not be loaded on the EDGs because it would require the operating unit train specific safeguards bus to lose power. This would reduce safety since the operating unit would have only one safeguards train available. Special test procedures were written to load the EDGs with the LOCA and shutdown loads. All four EDGs were to be tested.
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The inspectors reviewed Point Beach Test Procedure, PBTP 066, "G03/G04 Functional Test with U2 Accident Loads and U1 Cold Shutdown Loads," and determined that the appropriate FSAR automatic sequenced LOCA loads and non accident unit shutdown loads would be applied to the EDGs. A similar test was to be run for the G01 and G02 EDGs. The resident inspectors observed the actual performance of procedure PBRP
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The inspectors concluded that tha ORT-3 test met Technical Specifications and FSAR requirements. The licensee satisfactorily met commitment Item 27.
E4 Engineering Staff Knowledge and Performance E4.1 System Engineerino Performance a.
Insoection Scoon The inspectors evaluated the effectiveness of the System Engineering Review Board (SERB) Meetings and Oversight Reglew Board Meetings by attending meetings and reviewing board minutes.
b.
Qhtmations and Findings The inspectors noted that the SERB meeting agenda included action items sorted from the NUTRK system and problems identified by the system engineers. The meetings-consisted of a line by line item review. Discussions and clarifications were generally geared towards startup items and conservative decision making. Management was committed in supporting the SERB and the Oversight Review Board to ensure a thorough review was performed and that conservative decisions were made to resolve issues.
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CQDCluS1001 The inspectors concluded that the SERB and Oversight Review Board appeared to ask critical questions and sought a thorough understanding of relevant issues.
E7 Quality Assurancein Engineer!ng Activities E7.1 Coodition Reoort (CR) System a.
ADSDncilQalC002 The inspectors reviewed CRs and evaluated the licensco's actions for identifying and correcting weaknesses with the condition reporting system, b.
Observations and Findinos b1 WE Commitment l tem 23: * Review 20 percent of the Condition Reports closed since January 1,1995 which are associated with PSA safety significant systems for degraded equipment operabilityissues to en:ure that we have adequatelyidentified ard dispositioned operability issues. '
The licensee performed a 100 percent (235 CRs) review of risk significant, closed CRs issued since January 1995. This review identified 43 previously closed CRs that required additional reviews. An independent contractor review identified an additional eleven CRs which had been closed without sufficient documentation. The
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documentation was requireo to support equipment operability assessments. Five of the contractor identified CRs required an operability evaluation before Unit 2 restart.
Corrective actions were initiated by the licensee. Many of the reopened CRs lacked documentation to support full closeout or to address broader scope operability concerns, such as, to assess similar but currently nonhiled components for operability. The inspectors determined that the licensee and contractor review criterion was conservative and consistent with GL 91-18.
The inspectors reviewed licensee reopened CR Nos.96-964,96 827,96-829, and 96-1435. The additional action items completed or assigned for each of these CRs appeared to adequately address any system or component operability concerns.
The licensee's engineering staff indicated that 10 dedicated technical personnel with root cause training were now responsible for all CR closeouts, Their tasks were to ensure the CRs were properly documented, the evaluations were thorough, and the investigation was completed before closeout. These responsibilities were provided in NP 5.3.1, " Condition Reporting System," Revision 5. The inspectors noted that this procedure did not define "the Line Group PLA" or training requirements for these individual' The licensee indicated that the "Line Group PLA" were the 10 dedicated technical staff members assigned for all CR closeouts.
Procedure NP 5.3.1 implemented a four tier CR classification system (Level A through D) for screening CRs. This classification system gave specific examples and guidance on when/how root cause determinations were to be implemented for CRs. These
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changes appeared to add the appropriate guidance to ensure consistent and timely disposition of CRs.
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c.1 Conclusions The licensee exceeded their 20 percent CR review commitment by pedorming a 100 percent review, The inspectors reviewed the closed CRs identified by Attachment D of this report and concluded that the licensco satisfactorily met commitment item 23.
b.2 WE Commitment \\ ten 32: * implement interim improvements for the Condition Reporting process, based on a review of assessments andidentified recommendations for improving the process."
The inspectors reviewed the licensee's " Corrective Process Assessment," dated May 29,1997, This assessment identifled the source documents used to establish the interim CR improvement process. The assessment included findings from prior INPO
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condition reporting system evaluations, industry counterpart assessments, and event assessments, Interim CR process improvements included a CR categorization system, the development of a new CR handling system, and improvements in the operability and event evaluation process. The interim improvements were scheduled to be completed by June 30,1997.
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Many of the interim CR system improvements were completed before Unit 2 restart.
h The inspectors concluded that the licensee satisfactorily met commitment item 32.
E7.2 Quality Upgrade of the CREE a.
Insoection Scapa The inspectors reviewed the licensee's progress in upgrading the CREF to an Augmented Quality system.
b.
Observations and Findings The inspectors discussed the upgrading of the CREF system to an Augmented Quality system with the Quality Assurance (QA) group. The licensee indicated that the CREF would be upgraded over the next year from a non-quality, non safety system to a dedicated Augmented Quality system. All of the CREF work requests and material purchases for the last two months have been reviewed by the licensee's Augmented Quality program. The inspectors reviewed several QA Work Monitoring Reports and several Authorization to Release QA Material records for the CREF upgrade. The information resiewed appeared to be in order.
c, Conclusions The inspectors concluded that the licensee had the appropriate records and documentation to support the CREF system quality upgrade.
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EB Miscellaneous Engineering issues EB.1 (Closed) URI 50-301/96014 02(DRS): ASME Code Qualification Status of the Unit 2 SG Girth Welds.
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On November 15,1996, the inspectors identified a concem with the ASME Code qualification of weld procedure WPS GT SM/3.3 PB. This procedure was used to fabricate the Unit 2 replacement steam generator girth welds. The procedure had not been qualified in accordance with ASME Code,Section IX. This issue is discussed in Section E3.1.
E8.2 (Open)IFl 50 266/9601812(DRP): 50-301/9601812(DEPJ Lack of a CREF system description in the FSAR.
Since the OSTI, the licensee has written a draft FSAR section for the CREF that is scheduled to be included in the next FSAR revision. The inspectors reviewed a draft
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copy of the FSAR section. The draft appeared to provide the appropriate CREF system information. Much of the information included in the draft FSAR section was taken from the CREF Design Basis Document dated July 5,1995. This item will remain open pending NRC review of the approved FSAR change.
I E8.3 (Qlosed) IFl 50-266/9601813fDRP): 50-301/9601813IQRPJ Review outstanding f
questions pertalning to the control room ventilation and habitability DBD.
a.
loROClion Scope I
The inspectors reviewed control room habitability information pertaining to the questions or missing information identified in OSTI report 50 266/96018(DRP); 50-301/96018(DRP).
b.
Observations and Findings b.1 The habliability analysis used the wrona distance between the containment and th.e outside_ air.lalake This item was being tracked by CR 961776. The licensee revised the habitability calculation and determined that the ventilation system was operable, in addition, the correct distance was being used in the revised control room operator dose analysis that was currently under NRC review, b.2 The TSs reaulted preslute_droo across the combined HEPA and charcoal filleIS_Was more than the system could achigyn This item was being tracked by item DBDOl 31-004. The inspectors informed the system engineer that the purpose of this test was to identify dirty filters. Replacement of the filters would ensure that the system could supply the TS required flow rate. If the CREF system was not capable of meeting the required flow rate with a 6 INWC pressure drop across the combined HEPA and charcoal filters, then the TSs should be revised to reference the maximum pressure drop across the combined HEPA and
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charcoal filters that was obtainabie while still maintaining the TS required flow rate. The licensee acknowledged the inspectors observation.
b.3 The TSsieguired a laboratory charcoal test demonstrating 90 percent methyl lodide temoval efficiency while the habitability evaluation assumed 95 oercent This item was being tracked by CR 96 891. The 95 percent efficiency number was controlled by procedure HPIP 11.54," Control Room. F 16, Filter Testing." However, the Three Mile Island habitability analysis required 95 percent efficiency was never updated in the TSs. The licensee determined that the charcoal filters were operable as evident by the March 14,1996 laboratory charcoal sample test. The test showed that the charcoal efficiency was 99.62 percent. In addition, the licensee was proposing to increase the acceptance criteria for the laboratory charcoal sample test to 99 percent in l
a TS amendment that was currently under NRC review, tA4 Control Room dP Gauge Continuousiv Pegged High Since the OSTI, the licensee has calibrated the control room Magnehelic dP Gauge (DPI-47138), in addition, the licensee has issued a work order to purchase a new gauge that will have a wider range from -1 to +1 INWC rather than 0.25 to +0.25 INWC.
The licenseo plans to replace this gauge before Unit 2 startup.
b.5 Ihe lack of a orogram to verify the integrity of the_lsojation damoers Since the OSTI, the licensee had a contractor install six new inspection doors in the CREF duct-work to allow easier access for damper inspections. Using the new access doors, the licensee inspected all of the dampers required for control room Mode 4 alignment. The inspection included verification of smooth damper operation, full opening and closing of the dampers, and proper damper position indicailon in the control room. Adjustments or replacement of sealing surfaces were made as necessary, in addition, the licensee created annual call-ups which will initiate periodic inspections of the dampers, c.
Conclusions The inspectors concluded that the licensee had addressed the OSTI issues described above in an acceptable manner. This item is considered closed.
V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection resu'ts to members of sicensee management at the conclusion of the inspection on June 13,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
Attachments: As stated
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PARTIAL LIST OF PERSONS CONTACTED Licensee
- G. Boldt, Special Assistant to Site Vice President A. Cayla, Plant Manager F. Flentje, Regulatory Specialist W. Fromm, Maintenance Manager R. Grigg, President & Chief Nuclear Officer R. Harper, Shift Superintendent W. Herrman, Nuclear Supply Services Manager
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N. Hoefert, Continuous safety & Performance Assessment Manager R. Hornak, Senior Project Engineer Site Engineering
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P. Huffman, Senior Project Engineer Site Engineering D. Johnson, Regulatory Services & Licensing Manager P.Katers, Senior Project Engineer Engineering Evaluations C. Ksoblech, Fire Protection Engineer
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R. LaRhrett, Chemistry Manager R. Mende Operations Manager S. Patuiski, Site Vice President A. Reimer, Nuclear Engineering Manager B. Sasman, Senior Project Engineer-Civil Engineering J. Schweitzer, Site Engineering Manager R. Seizert, Training Manager G. Sigi, Instrument & Control Technician J. Thorgersen, Senior Project Engineer Ouality Verification V. Walther, Project Engineer DBD NBC J. McCormick Barger, Team Leader, Point Beach Oversight Team A. McMurtray, Senior Resident inspector
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INSPECTION PROCEDURES USED IP 40500:
Effectiveness of License Controls in identifying, Resolving and Preventing Problems IP 37550:
Effectiveness of the Engineering Organization to Perform Routine and Reactive Activities IP 50001:
Steam Generator Replacement inspection ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50 301/97010-01 IFl Review Unit 2 containment fan cooler performance test 50 266/97010-02; VIO Failure to follow NP 5.3.1 50 301/97010-02 50-301/97010-03 IFl Review approved calculation No. 97110 50 266/97010-04; eel Failure to meet Appendix R, Ill.G.2 requirements 50-301/97010-04 50-266/97010-05; eel Failure to meet Appendix R, Ill.L.1 requirements 50-301/97010-05 50 266/97010 06; eel Failure to incorporate appropriate qualitative acceptance criteria in 50 301/97010-06 the safe shutdown procedure 50-266/97010 07; eel Failure to provide adequate safe shutdown emergency lighting 50 301/97010-07 50 301/97010-08 VIO Failure to meet ASME Code qualification requiroments for the SG girth weld procedure Closed 50-301/96014-02 URI - SG girth weld procedure qualification 50 266/96018-13; IFl Con'rol room ventilation duct hatch 50 301/96018-13 Discussed 50-266/96018-07n; eel Review the resolution of the 90 millisecond reactor trip breaker 50 301/96018-07n opening time
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50-266/96018-12; IFl FSAR revision for control room ventilation system-50-301/96018-12 50-266/96018 21; URI
" Hot Smart Short" potential 50 301/96018 21
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LIST OF ACRONYMS USED AC Alternating Current AFW Auxillary Feedwater ASME American Society of Mechanical Engineers CO-Control Operator CR Condition Report CREF Control Room Emergency Filtration DBD Design Basis Document DC Direct Current DOS Duty Operating Supervisor dP Differential Pressure DSS Duty Shift Supervisor EDG Emergency Diesel Generator eel Escalated Enforcement item FSAR Final Safety Analysis Report GL Generic Letter GTAW Gas Tungsten Arc Welding HEPA High Efficiency Particulate Absolute
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IFl Inspection Follow up Item INWC inches of Water Column IST Inservice Testing IT Inservice Test JCO Justification for Continued Operation h
Kl Potassium lodide i
KV Kilo volt LER Licensee Event Report LOCA Loss of Coolant Accident LOOP Loss of Offsite Power-MCCB Mold Case Circuit Breaker MOV Motor-Operated Valve
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Management Supervisory Staff NP Nuclear Power Business Unit Procedure NRC Nuclear Regulatory Commission NRR-Office of Nuclear Reactor Regulation OM Operations Manual ORT Operations Refueling Test PLA Plant Title undefined PBNP Point Beach Nuclear Plant QA Quality Assurance QC Ouality Control SER Safety Evaluation Report SERB System Engineering Review Board SI-Safety injection SRO Senior Reactor Operator-TOL-Thermal Overload LTS Technical Specification URI -
Unresolved item VIO Violation WO
- Work Order
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Attachment A PROMPT OPERABILITY DETERMINATIONS CR 96-1680: Worst Case G03/G04 Loading Analysis may be Non conservative CR 90-1855: G03 Turbocharger Lube Oil Pressure Gauge
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CR 97 0363: Over temperature Delta Temperature and Over pressure Delta Temperature Setpoint Uncertainty Analysis may by Non-conservative CR 97 0385: Potential Failure of Redundant Safety related Circuits within the Main Control Boards CR 97-0606: G03 Voltage Monitoring Relay Calibration CR 97 0731: Nonconforming Diesel Generator G01 Day Tank, T-31 A, Level Control Circuit i
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Attachment B 50.59 SCREENINGS UPGRADED TO SAFETY EVALUATION REPORTS SER 97-017: Additional 120 Vac Receptacles and Lighting Inside the Unit 1 Containment SER 97-026: Unit i and Unit 2 Rod Insertion Limit Computer SER 97 030: Replace 1LC-473F, and Post Maintenance Test SER 97 035: Safety injection Checklist Revisions to Position SI 826A, P 15A/B Sl Pump Suction from BAST Series isolation in the Shut Instead of Open Position SER 97 039: MR 96-051 Replaces Supply Breakers for 1 AF-4002/2AF-4002 Control Circuits SER 97 049: Nittogen Piping and Regulator Replacement (RC 00441)
SER 97 050: Boric Acid and Reactor Make up Water Flow Transmitter Peplacement (Mechanical and l&C Work)
l SER 97-056: RP-1 A Preparation for Refueling
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SER 97 059: Deletion from FSAR of Large Pieces of Pipe as Potential Missiles (
SER 97 064: AM 3.3, At Power Primary to Secondary Leakage Monitoring Program
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SER 97 065: AOP 6A, " Low Boron Concentration Pockets in tha RCS" SER 97-070:. Install Oil Level Sight glass on HHSI Pumps 1P 15A/B
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SER 97-072: Blowdown Evaporator Piping Replacement SER 97-073: Replacement of the Existing Oil Sight glass on G04's EGB-13P Governor
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Attachment C SAFETY EVALUATIONS (SERs)
SER 97 005: U1/U2 RWST Recirculation Line Selsmic Upgrade SER 97 006: PBTP-047, "RHR Pump Maximum Flow Test" i
SER 97 009: ORT 3, Revision 28 SER 97 010: Preventing EDG Overload during S1 Pump Operation SER 97-011: Changes to Procedures IT 05 and IT 06 SER 97-012: Diesel Cooler Outlet Service Water Throttle Valves
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SER 97-013: CL 18 " Containment Integrity Unit 2," and CL 9D," Demineralized Water System"
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SER 97 015; Repair of SW ')0307 Valve SER 97-018: Maintenance Feedwater Bypass Control Valves Trim Replacement SER 97 019: Component Cooling Pump Replacement fE SER 97-022: Addition of Relief Valves to Containment Piping Penetration SER 97-023: Repair / Replacement of 6 inch SW Elbows on West SW Header
. SER 97-024: Verification of Containment Pressure ESF Test Switches Continuity SER 97-025: -Install Conduits and Cables to Resupply 2Y11,2Y21,2Y31, and 2Y41 SER 97-028: New Charging Pump Flow Gage for IST SER 97-032: Replace Breakers on 1Y-05 and 1Y-06 SER 97-033: Test the Ability to Cycle the Unit 1 to Unit 2 CCW Cross Connect Valves SER 97 035: Isolation of BAST from SI Suction SER 97-036: EDG G03 and G04 Generator Bearing insulation SER 97-037: Installation of Rosemount 3051C Differential Pressure Transmitters,1199 Diaphragm Remote Seals and Removal of Nitrogen Bubbler System for the Boric Acid Storage Tanks (BASTS) T-6A, T-6B and T-6C and Change Procedure Instrumentation and Control Procedure (ICP) 4.15," Boric Acid Tank Level Transmitter," and ICP 4.16 " Boric Acid Tank Level Calibration"
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4-SAFETY EVALUATIONS (BERs) (cont'd)
i" SER 97 040: WO 9702923 and 9702924 Soft Foot Check and Motor Current Analysis of Both P 38A M and P-38B M l
SER 97-047: Revise Crossover Stearn Dump System Arming Setpoint Found in FSAR Section
10.2.2, Provide Clarification of FSAR 10.2.2 by Adding the Auxiliary Governor j-Input (103%) to the Description of the Crossover Steam Dump System
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SER 97 050: Boric Acid and Reactor Make up Water Flow Transmitter Replacement
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(Mechanical and l&C Work)
SER 97-053: SLP 3 Revision
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f SER 97-054: Protection of Main Control Board Conductors in G01 and G02 Contre Circuits i
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SER 97 057: Unit 2 Loop A Channel Head Duct Supports
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SER 97-058: Unit 2 Channel Head Blower Intake Duct Modification
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SER 97-060: Dedicated Operator for P-38A USQ
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j SER 97-063: Replace 2P 116 Boric Acid Pump SEF 17 064: AM 3.3 Change in Primary to Secondary Leakage Monitoring Frequency
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O Attachment D CLOSED CONDITION REPORTS (CRs)
CR 92-0372: Lack of Ventilation Analysis for Safe Shutdown Equipment CR 94 0328: Unanalyzed Procedural Guidance for EDG Loading (G01/G02)
CR 95-0083: Instrument Air Flow Indicators Not Calibrated CR 95-0149: SW-2838 Failed its Stroke Test During IT-72 CR 95 0155: Potential SBLOCA Licensing Basis Safety Analysis Discrepancy CR 95 0205: Potentially inadequate Feed Flow to Steam Generators without Operator Action CR 95-0408: G03 Small Capacity Exhaust Fan Out of Service j
CR 95-0409: During Performance of TS 81 G03 Indications Spiked During Switch Transfer CR 95-0440: H52 G05 S Switch Linkage Over travel CR 95-0444: G02 Steady State Voltage Exceeded Expectations Following Load Rejection Testing CR 95-0489: Repetitive Failures of Thermal Overload Relays CR 95 0493: G02 Fails to Start During Attempt to Run in Exercise CR 95-0496: 50/51 Over Current Device of Unit i Station Service Transformer X13 Hi Side Breaker 1A52 58 Was Damaged CR 95-0526: G04 Declared Out-of Service Due to Failed Relay CR 95 0597: G02 Declared Out of-Service Per TS 82 CR 96 0070: lA System Copper Tubing Found Degraded CR 96-0080: Auxiliary Feedwater Pump 1P 29 Falls IT Test Due to Pressure Oscillations CR 96-0099: 2P 29 Auxiliary Feedwater Pump Declared Out of Service Due to Governor Oscillations CR 96-0119: Service Water Flow Switch Found Out-of Specification CR 96-0131: Diagnostic Testing of Component Cooling Water Surge Tank Vent CR 96-0136: Inadequate Breaker Coordination Causes Instrument Loss
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e CLOSED CONDITION REPORTS (CRs) (cont'd)
CR 96-0182; G01 Failed to Start During the Performance of TS 81 CR 96 0207: Chattering Field Brushes on G03 CR 96 0231: Safety related Protective Relay Setpoint was Out-of Tolerance Low CR 96 0265: Main Feed Pump Breakers Fail to Operate During Testing CR 96-0285: Failure of G01 Diesel Generator Governor CR 96-0553: Re Entryinto Cable Spreading Room l
CR 96-0567: Excessive Leakage on SFP Heat Exchanger Service W:mr Outlet Valve CR 9F 4642: G02 Raw Water Cooling Valve Failed to Open CR 96 0725: Work Plan Did Not Contain the Appropriate Documentation l
l CR 96 0727: Paint Peeling Inside G03/G04 Air intake Filters CR 96-0740: 4.16KV Breaker Maintenance CR 96-0850: Operability Determination Needed for issue Discussed in SER 96-028 CR 96-0889: Inadequate Coordination may Disable All Emergency Power CR 96-0959: Inadequate Procedural Guidance for Bus Stripping CR 96-0974: Containment Accident Fan Motor Cooling Concern CR 961230: Relief Valves Not installed Per Code Requirements CR 961322: Breaker Internal Wiring Not as Specified in Drawing CR 961327; Auxiliary Feedwater Pump is Operating Close to its Design Differential Pressure CR 961410: Auxiliary Feedwater Pump Discharge Check Valve Operability CR 961689: Failed Redundant Air Start Test CR 961772: Lack of Penetration at Root Weld of Excess Letdown Heat Exchanger Relief Valve Tailpipe CR 961839: - Use of a Level 3 Dedicated Operator for Auxiliary Feedwater When Pressure Control Valves are in Manual
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