IR 05000266/1998006

Insp Repts 50-266/98-06 & 50-301/98-06 on 980303-0413. Violations Noted.Major Areas Inspected:Licensee Operations, Engineering,Maint & Plant Support

ML20247D296
Person / Time
Site:	Point Beach
Issue date:	05/05/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20247D285	List: ML20247D280 ML20247D296
References
50-266-98-06, 50-266-98-6, 50-301-98-06, 50-301-98-6, NUDOCS 9805140331
Download: ML20247D296 (30)

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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket Nos:

50-266;50-301 Licenses No:

DPR-24; DPR-27 Report No:

50-266/98006(DRP); 50-301/98006(DRP)

Licensee:

Wisconsin Electric Power Company Facility:

Point Beach Nuclear Power Plant, Units 1 & 2 Location:

6612 Nuclear Road Two Rivers, WI 54241-9516 Dates:

fiarch 3 through April 13,1998 Inspectors:

F. Brown, Senior Resident inspector P. Louden, Resident inspector P. Simpson, Resident inspector Approved by:

J. W. McCormick-Barger, Cliief Reactor Projects Branch 7 9805140331 980505 PDR ADOCK 05000266 G

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EXECUTIVE SUMMARY Point Beach Nuclear Plant, Units 1 & 2 NRC Inspection Report No. 50-266/98006(DRP); 50-301/98006(DRP)

This inspection includM aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week inspection period by the resident inspectors.

Operations Operations personnel involved with the restart of the Unit 2 reactor exercised good

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control of reactivity changes. Clear, consistent communications were used by operators.

(Section 01.1)

A reactor operator who was "at the controls" for a unit that was shut down and defueled,

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left the authorized surveillance area for a short period of time without being appropriately relieved by another reactor operator. This action was contrary to the requirements of the licensee procedure for the conduct of operations and was a violation of Criterion V,

" Instructions, Procedures, and Drawings," of 10 CFR Part 50, Appendix B. (Section 01.2)

Operators responded appropriately when the second stage seal of an idle reactor coolant

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pump partially opened. Planning of the pump restart and communications and procedure adherence during the restart were appropriate and effective. (Section O2.1)

The use of tape to cover the bearing grease port of the residual heat removal pump motor

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instead of the vendor-designed cover reflected an acceptance of substandard conditions by auxiliary operators. (Section O2.2)

Maintenance Main control board wire separation work was conducted in a professional and thorough

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manner. All work observed was performed with the appropriate work order plan present and in active use. (Section M1.1)

Maintenance and health physics organizations were not effectively prepared to perform

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the lower intemals lift based on planning meetings conducted 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the initiation of work. Early in the evolution, maintenance workers failed to follow procedures resulting in a violation of Technical Specification 15.6.8.1. Laterin the evolution, the maintenance organization displayed better control of the activity, and the lower intemals were moved without incident. (Section M1.2)

Many observed maintenance activities were completed in accordance with requirements

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specified in administrative and work control procedures. However, ceases were noted where administrative requirements were not being implemented. Some of the corrective actions for these issues were narrowly focused, and the effort to address the inconsistencies in application of administrative requirements within the maintenance department was not an integrated effort. (Section M1.3)

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Maintenance and operations department freeze seal pre-evolution briefings held on

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March 17,1998, were thorough and covered command and control responsibilities, expected communication standards, and contingencies. Teamwork between different disciplines was evident and participants displayed a good questioning attitude.

(Section M1.5)

Enaineerina A ventilation control panel in an emergency diesel generator room was misclassified as

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nonsafety-related. The licensee's initial corrective actions did not include determining if operability of the system had been challenged while the component was incorrectly classified as being nonsafety-related. (Section E1.1)

l The licensee identified and corrected two cases where valves between seismically

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l qualified piping systems and non-qualified piping systems were not maintained in a I

closed position as required by the Final Safety Analysis Report. (Section E1.2)

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Offsite, corporate office-based engineering personnel working on a corrective action

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commitment initiative to assess the adequacy of a separation of seismically qualified and

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non-qualified piping systems were performing analyses and taking credit for components to function in a manner that may not have previously been considered in the design basis.

The engineers had not evaluated whether such reliance might constitute a design basis j

change. Additionally, onsite licensee personnel performing concurrent and interrelated

corrective action initiatives had not been informed of the potential design engineering activities that could have affected the results of these other initiatives. (Section E1.3)

The inspectors concluded that the 125-Volt direct current (Vde) system was capable of

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l meeting design basis functions. However, the failure to maintain an up-to-date battery loading calculation was considered a violation of 10 CFR Part 50, Appendix B, Criterion Ill, " Design Control." (Section E3.1)

The reactor engineering organization did not provide accurate critical rats position data to

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l operations personnel during an initial attempt to startup Unit 2. The problems revealed

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during the startup were considered additional examples of reactor engineering performance concems which were the subject of a Notice of Violation from Inspection l

Report No. 50-266/98003(DRP); 50-301/98003(DRP). (Section E3.2)

l The practice of duty technical advisors (DTAs) serving two consecutive 24-hour watches

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was not consistent with the intent of program procedures and raised questions regarding the DTA's fitness-for-duty. Although, no specific performance issues were identified as a result of the DTA standing consecutive watches, licensee management immediately revised expectations regarding this practice to preclude potential fitness-for-duty issues.

(Section E6.1)

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Plant Support Perronnel exposures during the Unit i refueling outage were meeting established

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licensee goals. The number of personnel contamination events was higher than l

anticipated; however, most of the events were minor shoe contaminations. The health physics manager initiated a review of the causes for the higher than anticipated number of personnel contamination events. None of the events resulted in significant exposure of

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personnel. (Section R1.1)

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i Report Details Summary of Plant Status During this inspection period, Unit 1 was shutdown in a continuation of the Cycle 24 refueling outage. ' Unit 2 was shutdown on March 5,1998, in accordance with Technical Specification (T/S) 15.3.0., because the compenent cooling water (CCW) system was declared inoperable.

Detailed engineering analysis subsequently determined that the CCW system was operable.-

Unit 2 was restarted on March 28,1998, and operated at 100 percent power for the remainder of the inspection period.

Inspection Focus l

j During this inspection period, the inspectors focused on conduct of plant operations, continued a vertical slice review of the 125-volt direct current (Vde) system, and completed routine inspection activities.

l 1. Operations

Conduct of Operations l

01.1 Unit 2 Reactor Startuo (Inspection Procedure (IP) 71707)

During the restart of the Unit 2 reactor on March 28,1998, problems encountered during the attempt to make the reactor critical resulted in the licensee suspending the criticality l

attempt. The reactor was made critical later the same day following a review of the earlier problems and a recalculation of the estimated critical rate position. Problems associated with the initial estimated critical rate position calculation are discussed in Section E3.2 of this report. Operations personnelinvolved with the restart of the Unit 2 reactor exercised good command and control of reactivity changes and used clear, consistent three-way communications.

01.2 Unit Operator Left the Authorized "At the Controls" Area a.

Inspection Scope (IP 71707)

The inspectors reviewed the circumstances regarding the failure of an onshift reactor operator (control operator (CO)) to remain within authorized surveillance areas in the control room.

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Observations and Findingg

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The inspectors were in the control room monitoring a Unit 2 non-routine activity on

March 14,1998. At approximately 9:00 p.m., the inspectors noted that the Unit 1 CO was l

not in an authorized surveillance area for Unit 1, which was defueled at the time. Shortly i.

thereafter, the Unit 1 CO reentered the authorized surveillance area from the control room back panel area. The CO was absent from the authorized area for about one minute.

The T/S minimem manning requirements were satisfied during the CO's absence; i

however, Operations Manual (OM) 1.1, " Conduct of Plant Operations," Revision 1,

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Attachment 2, Paragraph 2.3, required the reactor operator "at the controls" to remain in the authorized area unless relieved. The inspectors discussed the CO's absence from the authorized area with the duty operating supervisor (DOS, a senior reactor operator).

The DOS stated that the CO had been released from the authorized area for a short period of time, and that this was acceptable because Unit 1 was defueled. The inspectors pointed out that OM1.1 allowed no exceptions. This issue was further discussed with the operations manager, who acknowledged that OM 1.1 required the unit CO to remain in the authorized area under all fuel loading conditions. The failure of the Unit 1 CO to remain in the authorized area was a violation (VIO 50-266/98006-01(DRP))

of 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"

which requires that activities affecting quality be performed in accordance with procedures. Condition Report (CR) 98-1075 was written to document this event, and the operations manager sent all operators an electronic memorandum which reiterated the requirements of OM 1.1 for an operator "at the controls."

The inspectors also identified a discrepancy in OM 1.1. Figure 1 and Section 2.8 of Attachment 1 differed concoming the control room area the DOS was to occupy. The licensee's practice was to allow the DOS to sit on a raised platform in the control room, which was consistent with Section 2.8 but was not allowed by Figure 1. The inspectors identified the discrepancy to the duty shift superintendent (DSS, a senior reactor operator). The DSS stated the discrepancy had already been identified by operations personnel via the procedure change process about six months earlier but was not yet corrected. The DSS wrote a CR to document the discrepancy on March 19,1998. This discrepancy was corrected the same day with a temporary procedure change.

During this inspection period, the inspectors noted that the operations department had a significant number of outstanding procedure change requests and was in the process of upgrading operations procedures. Licensee management indicated that priorities were set to accomplish the procedure upgrade work within existing resource constraints. The correction of OM 1.1, identified six months earlier by operators, was not high in the priority scheme. The inspectors commented to operations management that procedural adherence and operator identification of needed procedure changes may be adversely affected given the large backlog which impacted the timeliness of processing procedure changes. However, the inspectors noted that progress was being made in upgrading operations department procedures overall.

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Conclusions The inspectors concluded that the CO who left the "at the controls" area for a bnef time on March 14,1998, without obtaining an appropriate relief, was not performing duties in accordance with OM 1.1. This was considered a violation of 10 CFR Part 50, Appendix B. The inspectors also identified a discrepancy in OM 1.1, which the licensee subsequently corrected. The procedure upgrade program contained a substantial backlog of identified changes that needed to be made; however, a prioritization list was being followed and some progress was being made.

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Operational Status of Facilities and Equipment O2.1 Reactor Coolant Pumo (RCP) Seal Leakaae a.

(nspection Scope (IP 71707)

The inspectors reviewed the licensee's response to excessive leakage from the Unit 2 "B" RCP (2P-1B) second stage seal.

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Observations and Findings On March 10,1998, operators noted excessive flow through the second stage seal of RCP 2P-1B. Unit 2 was in cold shutdown and reactor coolant pressure was 300 pounds per square inch gauge (psig) with the "A" RCP (2P-1 A) operating and the "B" RCP (2P-1B) idle. Upon the discovery of the excessive seal leakage, the operating crew entered

Abnormal Operating Procedure 18. "RCP Malfunction," Revision 8. In accordance with i

that procedure, pump 2P-1 A was secured, the reactor was depressurized to about i

50 psig, and tne RCP seal water retum valves were closed. These actions terminated

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the excessive flow. The inspectors noted thet the operating crew referenced the j

appropriate T/S for reactor coolant system leakage. The licensee wrote a condition report I

to document the event.

l The licensee formed a multi-disciplinary team to assess the condition of the 2P-1B seal package and concluded that the second stage seal had partially opened, but had not failed. A temporary change was made to Operating Procedure (OP) 3C, " Hot Shutdown

to Cold Shutdown," Revision 69, to provide instructions for starting 2P-1B to allow for further evaluation of the seal's condition. The inspectors reviewed the change to OP 3C and the referenced sections of OP 4B, "RCP Operation," Revision 34, and concluded that the changes were appropriate for the circumstances. An operating crew started RCP 2P-1B without incident on March 14,1998. The second stage seal reseated during the pump start. The inspectors observed appropriate and effective communications, planning, and performance of pump start activities in the control room during this evolution.

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Conclusions Operators responded appropriately when the second stage seal of an idle RCP partially l

opened. Planning of the pump restart and communications and procedure adherence during the restart were appropriate and effective.

O2.2 Residual Heat Removal (RHR) Pump Motor Grease (IP 71707)

i During a routine walkdown of safety-related systems, the inspectors identified a

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discrepancy in the amount of grease present on the outboard bearings of the l

l four RHR pump motors. The amount ranged from grease fully covering the bearings to being hardly visible. The inspectors also noted that tape was used to cover the Unit 1 RHR "A" pump motor outboard bearing grease port in lieu of the vendor-designed i

cover. When notified of the findings, the component engineers investigated the situation and informally determined that the pumps were still operable. Operations personnel

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wrote a condition report regarding the matter and requested a formal operability I

determination (OD). The licensee concluded in the OD that the pumps remained operable.

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The inspectors concluded that the bearing grease levels were not an operability concem.

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However, the use of tape to cover the bearing grease port of the safety-related RHR pump instead of the vendor-designed cover reflected auxiliary operator acceptance of substandard conditions.

O3 Operations Procedures and Documentation

O3.1 Update on Station Wide Procedure Uparade Proaram (IPs 71707. 62707. and 37551)

In a previous inspection report (No. 50-266/97020(DRP); 50-301/97020(DRP)), the inspectors opened an inspection follow up item (IFI) to evaluate the licensee's ongoing procedure upgrade program and verify that:

j upper tier administrative procedures for procedure adherence and procedural

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control of activities were consistent wia the current licensing basis and NRC guidance, i

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the methods for establishing procedural controis were commensurate with J

L licensee staff training and supervisory oversight such that activities affecting i

safety were performed in a controlled manner and with predictable results, and the licensee's process for assuring that work plans were not inappropriately used

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to circumvent procedural change requirements were adequate.

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I Over the past six months, the inspectors have identified several instances where procedural controls were either inadequate for the circumstances or were not adhered to l

by licensee personnel. Sections 01.2, M1.2, M1.3, and E3.2 of this report discuss other i

examples of procedural problems still evident at the station.

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I Notwithstanding these problems, the inspectors have noted an increased sensitivity to procedural quality issues and some progress in upgrading procedures. Additionally, insufficient time has passed to determine the effect of the licensee' procedure upgrade project. Therefore, the inspectors will leave IFl 50-266/97020-02(DRP);

50-301/97020-02(DRP) open for an additional six-month period to track the programmatic aspects of procedure content, use, and adherence.

Quality Assurance in Operations 07.1 Operations Quality Assurance Audii(IP 71707)

The inspectors attended a quality assurance department audit exit on March 13,1998.

The audit focused on operations department administrative controls and operator

performance. The meeting was well attended by operations department personnel and plant management. Operations management was receptive to the auditors' findings. The inspectors noted that most of the findings from the audit were more administrative in nature rather than performance-based. The inspectors subsequently reviewed the issued

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audit report (No. A-P-98-03) and verified that the issues discussed at the exit meeting were consistent with those documented in the report.

08 Miscellaneous Operations issues 08.1 (Closed) Licensee Event Report (LER) 50-266/98004: 50-301/98004: Resc.or coolant pump lube oil collection system design nonconformance with Appendix R, Section 111.0.

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This issue was discussed and dispositioned in accordance with the NRC Enforcement Policy in inspection Report No. 50-266/98003(DRP); 50-301/98003(DRP), Section O2.1.

No further action is necessary regarding this matter.

08.2 (Closed) LER 50-301/98002: Reactor coolant pump component cooling water retum line I

check valve found seriously degraded. The CCW system containment retum check valve (2CC-745) was radiographer and found in the open position. This valve provides a redundant means for preventing loss of CCW fluid in the event of a failure of a CCW pipe j

inside the containment. The licensee rebuilt the intamals of the valve and the repairs

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i were deemed to be adequate. The inspectors had no further questions regarding this I

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l II. Mainte_n_ance M1 Conduct of Maintenance M1.1 Main Control Board Wire Separation Maintenance Activities

[nLspection Scope (IP 62707)

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r The inspectors observed and reviewed the following maintenance activities which were part of the corrective actions to resolve discrepancies between redundant safety-relsted equipment:

Work Order Plan 9705320, " Sleeve / Wrap Cables For Circuit 1 A-06 Bus l

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Voltmeter," and Work Order Plan 9705324, " Sleeve / Wrap Cables For Circuit Supply

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Breaker 1 A52-77 to Bus 1 A-04."

The planned activities included separating and sleeving electrical wires in some control room panels associated with control and indication circuits for the Class 1E electrical buses and power sources, b.

Observations and Findinos The scope of the planned cable separation work required entry into the T/S 15.3.7.B.1.g.

limiting condition for operation (LCO) for Unit 2 (Unit 1 was defueled at the time) since the

' B" train of the 4.16-kilovolt bus safeguards switchgear (Bus 1 A-06) did not have its emergency power source available because of the protective tagout boundary. The inspectors verified that the appropriate T/S LCOs had been entered for the plant conditions and scope of planued work.

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The inspectors noted good coordination and communication between the work control center, control room, and maintenance personnel. The job supervisor briefed the control room personnel on the specifics of each work order plan and walked through each package with the maintenance crew doing the work. Quality control personnel were l

present whenever required by the work order plans and quality control hold points were properly verified and signed off.

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l The maintenance crews used self-verification checks in the cramped and sensitive work j

environment. Workers also displayed good questioning attitudes during the course of the i

work. Worker-identified discrepancies in work plans were called to the attention of l

maintenance supervision and corrected appropriately.

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Conclusions

l The inspectors concluded that the control board wire separation work was performed in a

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professional and thorough manner, All work observed was performed with the appropriate work order plan present and being appropriately referenced.

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M1.2 Unit 1 Reactor Vessel Lower intemals Lift a.

Inspection Scope (IP 62707)

The inspectors observed the planning and execution of the Unit i reactor vessel (RV)

i lower intemals lift.

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Obser<ations and Findinas -

The inspectors attended a work preparation briefing on March 3,1998, which was held to discuss the various aspects of the lower intamals lifting evolution. Work group l

responsibilities were identified and Routine Maintenance Procedure (RMP) 9053, "RV Intemals Removal and Installation," Revision 1, was reviewed. Health physics

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considerations were discussed; however, radiation work permits had not been completed.

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The inspectors made the following observations regarding the briefing:

Contrary to Nuclear Procedure 1.2.6, " Infrequently Performed Tests and

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Evolutions," Revision 4, the work activity was not categorized as an infrequently performed test or evolution. This condition was subsequently corrected prior to the beginning of work.

Health physics information discussed was not complete nor fully evaluated prior

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to the planning meeting. For example, the radiation work permits had not been prepared.

l Overall, discussions at the briefing (held 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before the initiation of work)

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indicated that many aspects of the job had not been thoroughly evaluated.

The initial attempt to lift the lower intemals was performed under the direction of a maintenance supervisor. A senior manager was present in the containment to provide oversight. The inspectors observed that the maintenance crew attached the containment

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polar crane hook to the "intemals lift rig," a special lifting platform, without inserting a load cell between the hook and lift rig, as required by Step 7.3.7.f. of the RMP. The purpose of the load cell was to provide early indication of binding during crane load vertical movement. The inspectors asked the maintenance supervisor why this step had not been completed. The supervisor stated that the lift rig was to be moved to the other side of the containment and the load cell would then be installed. This action would have been acceptable, since the procedure specifically only prevented the lifting rig from being positioned above the reactor vessel without the installed load cell. However, the crew l

proceeded with positioning the lift rig above the RV with the intent of lowering the lift rig into place on the RV and then installing the load cell. Positioning the intemals lift rig above the reactor vessel without the load cell installed was a violation (VIO 50-266/98006-02(DRP)) of T/S 15.6.81 for failure to follow procedures. Prior to the lift rig being lowered onto the RV, the senior manager in containment recognized that the procedural requirements were being violated and stopped work. The action was documented on CR 98-0831. A temporary change was made to RMP 9053 to allow installation of the load cell after the lift rig was landed on the RV While the procedure change was being processed, involved maintenance personnel stated that the original procedure had been ir;dequate. The inspectors concluded that the steps in the original procedure could have been performed as written. Additionally, the inspectors noted that maintenance staff had ample opportunity during the pre-job briefing to decide how to perform the steps as written or to identify attemate ways to perform the lift, and make any

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necessary procedural changes.

The maintenance crew attempted to lower the lift rig onto the RV after the temporary change was processed for the RMP. The three guide bushings on the lift rig were not proper 1y aligned with the three guide studs in the RV flange, and at least one bushing was observed to be resting on the corresponding guide tube. The full weight of the lift rig appeared to be placed on the guide bushings which were resting on top of the guide studs. The crane operator could not quickly identify the misalignment because the load cell was not present to indicate reduced weight on the crane as the crane hook was lowered. The lift rig was raised off the guide studs and rotated into proper alignment. On the second attempt at lowering the !ift rig, the mounting plates for two of the guide bushings were found to have been knocked out of alignment to the extent that the guide bushings would no longer slide down the guide studs. The lift rig was transferred back to a laydown area, and the guide bushing mounting plates were realigned. Lifting operations were suspended to allow for a shift change of personnel.

A pre-job briefing was conducted for the on-coming shift personnel. Overall, the briefing was conducted well. The maintenance supervisor in charge of the evolution displayed a clear understanding of the task and clearly outlined roles and responsibilities of the work

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crew members. During the conduct of the intemals lift, the maintenance supervisor maintained a " big picture" oversight of the activity. Having noted the procedural compliance problems during the previous shift, the work crew leader was deliberate in taking actions and frequently referenced the RMP to ensure steps were appropriately completed. The lift was conducted very methodically and was controlled well. The lower intemals were placed in the storage area of the Unit 1 cavity area without incident.

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Conclusions The inspectors concluded that the maintenance and health physics organizations were not adequately prepared to perform the lower intemals lift based on planning meetings conducted 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the initiation of work. In addition, early in the evolution, the inspectors identified a failure of maintenance workers to follow procedures as required by T/S. This was considered a violation. Later in the evolution, the maintenance organization displayed better control of the activity and the lower internals were moved without incident.

M1.3 Inconsistent Application of Administrative Controls in Maintenance a.

Inspection Scope (IPs 62707 and 40500)

The inspectors assessed the maintenance department's implementation of administrative controls, including procedure adherence.

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Observations and Findinas Maintenance personnel were observed to be performing many maintenance activities in full compliance with procedural and other administrative controls. However, the failure to utilize the procedural controls in place during the lower intemals lift, and the failure to effectively utilize the pre-job brief to ensure the appropriateness of the planned method of

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performing work during the lower intemals lift, described in Section M1.2 above, were indicative of inconsistencies in the maintenance department's application of standard administrative controls. The inspectors identified two other minor discrepancies in the application of administrative controls by the maintenance department during this period.

These conditions were discussed with licensee staff and were corrected under CR 98-0917 and CR 98-1168. Additional,' unrelated examples of inconsistent application of administrative controls were identified by the licensee, and were documented in CR 98-1369 ar~i CR 98-1463. Similar issues were discussed in Section M2.2 of IR No. 50-266i98003(DRP); 50-301/98003(DRP).

l Specific corrective actions were taken for each identified discrepancy, but the inspectors noted that there was no broad-based initiative to address the observed discrepancies.

j Additionally, some of the corrective actions were narrowly focused. For instance, the only corrective action documented for the RV lower intemals lift procedure violation (CR 98-0831) was a permanent change to the procedure to add greater flexibility in the performance of work steps. This did not appear to address all of the performance issues discussed in Section M1.2 above. This concem was discussed with the maintenance manager, who indicated that the performance discrepancies were not pervasive, and that

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various initiatives were in place to improve the performance of maintenance activities.

i The maintenance manager further stated that a coordinated effort to address both long-

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term corrective actions and interim actions within the department was worth consideration.

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Conclusions Many of the maintenance activities observed were completed in accordance with requirements specified in administrative and work control procedures. However, the

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inspectors noted cases where administrative requirements were not being implemented.

l The licensee's corrective action program also identified similar examples of this problem.

Some of the corrective actions for these issues were narrowly focused and lacked an integrated effort to address the inconsistencies in application of administrative controls i

within the maintenance department.

M1.4 Troubleshooting a Breaker Indication Failure l

The inspectors reviewed the licensee's troubleshooting and corrective actions for a failure of the control room indication for motor-driven auxiliary feedwater pump P-38A. The associated work order Packages 9708867 and 9804735 were complete and thorough.

No administrative or technical concems were identified.

M1.5 Freeze Seal for Repair of Component Coolina Water Check Valve. 2CC-745 (IP 61707)

The licensee used a freeze seal to assist in the performance of a visual inspection and repair of 2CC-745. The inspectors verified that the licensee had taken appropriate measures to address industry-related problems with freeze seals. Maintenance Procedure RMP 9327, "CC-745 Swing Check Vane Inspection," Revision 0, and 10 CFR 50.59 safety evaluation (SE)98-037 contained requirements that reflected these l

measures and were determined to be adequate by the inspectors.

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The inspectors attended the maintenance and operations department freeze seal pre-evolution briefings held on March 17,1998. The briefings were thorough and covered command and control responsibilities, expected communication standards, and i

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displayed a good questioning attitude. The licensee completed inspection and repair of

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2CC-745 as planned.

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M8 Miscellaneous Maintenance issues M8.1 (Closed) LER 50-301/95006: PORV (Power-Operated Relief Valve) Post-Maintenance l

Testing Not Performed Prior to Establishing LTOP (Low Temperature Over-Pressure l

Protection). The licensee identified that LTOP was not properly established after the i

reactor vessel head was reinstalled because one of two PORVs required for LTOP was inoperable. The valve was considered inoperable because post-maintenance testing had not been completed. A root cause evaluation by the licensee identified that a l

misunderstanding in the work control center resulted in the post-maintenance test for the l

valve not being performed before the reactor head was reinstalled. With the reactor head installed, LTOP was required. In addition, control room operators were unaware that the l

post-maintenance test had not been completed.

Two operable PORVs were required for LTOP, but the T/S allowed one valve to be

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inoperable for a limited time period. The licensee was allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to restore the

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inoperable PORV and an additional 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to depressurize and vent the reactor coolant system if the PORV could not be made operable. However, the valve was inoperable for about 34 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br /> and the reactor coolant system had not been depressurized or vented.

Licensee management counseled operators and work control center staff on the inappropriate delay in completing the post-maintenance test and revised several

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procedures to highlight the need for PORV operability (and establishing LTOP) prior to reactor head installation. The problem has not reoccurred and an extensive review of the post-maintenance testing process by the licensee in the past year, with concurrent NRC monitoring of that review (see, for example, Sections M1.1 and M3.1 of IR No. 50-266/97010(DRS); 50-301/97010(DRS), has given further assurance that this will remain an isolated event. This licensee-identified and corrected violation is being treated as a non-cited violation (NCV 50-301/98006-03(DRP)), consistent with Section Vll.B.1 of the NRC Enforcement Policy.

M8.2 (Closed) IFl 50-266/%002-01(DRP): 50-301/96002-01(DRP): This IFl comprised several inspector concems generally related to work planning and scheduling. One of those concems was that an SE which addressed equipment operability could be prepared and approved without control room personnel being made aware of possible changes to the operability status of plant equipment specified in the SE. Because of this and other problems with the SE process, the licensee reviewed numerous existing SEs, extensively l

restructured the goveming procedure for conducting an SE, trained plant staff on the revised procedure, and established a multi-disciplinary team of which a member would review all SE screenings. Recent NRC inspections (irs No. 50-266/97010(DRS);

50-301/97010(DRS) and No. 50-266/97023(DRS); 50-301/97023(DRS)) have identified that the SE process has improved. The original concem of this IFl has been adequately addressed.

A second concem pertained to the concurrent use of a CCW pump as the redundam pump for two other CCW pumps. This concem was adequately addressed with the revision (in June 1997) of T/S 15.3.3.C. for the CCW pumps. This revision removed the previous ambiguity on redundant pumps and does not allow the use of a CCW pump assigned to one Unit as a redundant pump for the other Unit.

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The remaining two items pertained specifically to poor planning and scheduling of work

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on an emergency diesel generator (EDG) and a CCW pump. Recent inspection reports (irs No. 50-266/97003(DRP); 50-301/97003(DRP), No. 50-266/97006(DRP);

50-301/97006(DRP), No. 50-266/97013(DRP); 50-301/97013(DRP), and No. 50-266/97021(DRP); 50-301/97021(DRP)) document additionalinstances of poor work planning and scheduling. Although none of these items involved violations of NRC requirements, they indicated that the work planning and scheduling process was weak As discussed in IR No. 50-266/97006(DRP); 50-301/97006(DRP), the licensee has recently undertaken several initiatives following an extensive maintenance program improvement review. Because the implementation of these programmatic initiatives is being tracked as an IFl (50-266/97006-02(DRP); 50-301/97006-02(DRP)) and the original SE and CCW concems discussed above have been adequately addressed, the two concerns about specific work planning and scheduling problems are considered closed.

M8.3 (Closed) LER 50-266/97042: Failure to perform containment personnel air lock surveillance while door interlock is inoperable. The events and circumstances of this LER were discussed in IR No. 50-266/97021(DRP); 50-301/97021(DRP), Section M2.1. A Notice of Violation was issued regarding this matter. Therefore, this LFR is considered l

closed with the existing open violation (VIO 50-266/97021-02(DRP);

i 50-301/97021-02(DRP)) serving as the inspection tracking mechanism for completion of the corrective actions.

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lil. Enaineerina E1 Conduct of Engineering E1.1 EDG Room Ventilation System Safety Classification a.

Inspection Scope UP 37551)

The inspectors reviewed aspects of the safety classification of the EDG room ventilation systems.

b.

Observations and Findinas The inspectors reviewed the safety classification of the G-01 and G-02 EDG room ventilation system components. This review was performed while independently assessing the technical merits of an OD associated with EDG output ratings at elevated room temperatures. The inspectors noted that the G-01 exhaust fan control panel (C-032) was classified as safety-related; however, the G-02 exhaust fan control panel (C-036) was classified as nonsafety-related. The inspectors questioned the system engineer about this difference. After reviewing the component history, the system engineer determined that the list of safety-related components had not been appropriately updated to add C-036 as committed to in LER 50-301/91001-01. This problem was documented in CR 98-1084.

The inspectors reviewcd the corrective actions for CR 98-1084 to ensure that the issue had been adequately addressed. The corrective actions consisted of a broad review of the EDG room ventilation system to determine whether any other discrepancies existed, and a review to determine whether the condition was reportable. While these two corrective actions were appropriate, both the CR and the corrective action documents specified that the as-found condition was administrative in nature. The problem could have been more substantial had the appropriate configuration and material controls not been maintained between the time C-036 was dedicated as being safety-related and the identification of the error. The inspectors communicated this concem to the appropriate system engineering supervisor, who initiated an additional corrective action to review the maintenance and modification history of C-036 to ensure that its configuration and material status had not been compromised. No problems were identified during this review.

The inspectors considered the safety significance of this specific issue to be minor; therefore, the failure to implement effective corrective actions regarding the safety classification of C-036 (with respect to LER 50-301/91001-01 and CR 98-1084) was a

. non-cited violation (NCV 50-301/98006-04) of 10 CFR Part 50, Appendix B, Criterion XVI,

" Corrective Action," consistent with Section IV of the NRC Enforcement Policy.

c.

Conclusions The inspectors identified a minor discrepancy in the licensee's list of safety-related components. Specifically, a ventilation control panel in an EDG room was misclassified.

The licensee's initial corrective actions did not include determining if the ventilation system operability had been challenged while the component was incorrectly classified as

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being nonsafety-related. Subsequent review indicated no problems in this area and the discrepancy was corrected.

E1.2 Seismic Isolation in Pipina Systems a.

Inspection Scope (IP 92700)

The inspectors reviewed two LERs that dealt with discrepancies conceming the conformance of plant piping systems to Final Safety Analysis Report (FSAR)

commitments.

b.

Observations and Findinas Licensee Event Report 50-266/97021 documented the failure to maintain two valves in the spent fuel pool (SFP) cooling system in a normally closed position. These two valves separated seismically qualified portions of the SFP cooling system from non-seismically qualified portions of the system. Licensee Event Report 50-266/97028 documented that piping which was not seismically qualified was connected to the seismically qualified refueling water storage tank (RWST) by way of normally open valves. The FSAR requires that valves which separate seismically qualified from non-seismically qualified systems be normally closed.

The licensee initiated a broad assessment of a!I systems which contained a seismically qualified to non-qualified interface. Corrective actions were planned for all pipe systems where adequate system separation did not exist. These actions were discussed with the j

NRC during public meetings and were documented in docketed letters to the NRC dated July 25,1997 (NPL 97-0432), and December 19,1997 (NPL 97-0803). The inspectors reviewed the documentation associated with this issue and considered the docketed information to be accurate and comprehensive. The corrective actions were considered to be appropriate. This licensee-identified and corrected, non-repetitive failure to maintain the SFP cooling system and RWST recirculation pipe isolation valves in the design position (normally closed), was a non-cited violation (NCV 50-266/98006-05(DRP);

50-301/98006-05(DRP)) of 10 CFR Part 50, Appendix B, Criterion lil, " Design Control,"

cor.sistent with Section Vll.B.1 of the NRC Enforcement Policy, C_ nclusions o

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The licensee identified and implemented effective corrective actions for two cases where valves between seismically qualified piping systems and non-qualified piping systems were not maintained in a closed position as required by the FSAR.

E1.3 Maintaining Desian Basis Inteority l

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Inspection Scope (IP 37551)

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The inspectors reviewed the current status of licensee actions to ensure conformance of plant piping systems to FSAR commitments.

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b.

Observations and Findinas

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The inspectors discussed the status of the licensee's ongoing assessments of the adequacy of the separation of seismically qualified and non-qualified piping systems with the cognizant design engineering personnel. The engineers described the screening process being used to determine whether various systems were in conformance with the FSAR commitments, and whether modifications would be required for systems and components which were operable, but not in compliance with the existing FSAR. The screening criteria included the identification of motor-operated valves and check valves which could serve the function of a normally closed valva. When such motor-operated valves or check valves existed, additional corrective actions for those systems were not considered necessary to address the seismically qualified to non-qualified separation concem. However, the criteria did not require the evaluation of whether such motor-operated valves or check valves were considered seismic-class boundsry valves in the system design and licensing bases.

The inspectors asked whether the screening criteria had been discussed with the onsite licensee staff performing rebaselining reviews of the inservice testing (IST) program and the FSAR. The engineers inrifcated that such discussions had not taken place. The I

inspectors subsequently determined that the IST and inservice inspection programs could have been affected by the seismic review program screening criteria, and that the IST

system engineer had not been aware of the seismic review until after the inspectors

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questioned the design engineering personnel. While this issue may have eventually been i

identified by the licensee through supervisory reviews of the results of this seismic review l

program, the inspectors considered the failure to integrate the seismic review program

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with the IST testing program review a weakness.

The licensee had several ongoing, parallel improvement initiatives which were in response to previous NRC enforcement actions. These included development of design

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basis documents, a verification and update of the FSAR, rebaselining the IST program, reviewing the inservice inspection program, rewriting system operating procedures, and updating the IST procedures. Changes in system design basis, such as the addition of a safety-related function to an existing valve, brought about by licensee staff working on one of these efforts, could negatively affect the other improvement initiatives if not properly documented and coordinated. The inspectors reviewed the licensee's response to the latest Systematic Assessment of Licensee Performance, report No. 50-266/97001; 50-301/97001, and found that the licensee acknowledged the need to

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control design basis changes when making plant hardware changes, but that there was l

no specified initiative to control the effects of design basis changes that might occur as j

the result of analysis or software changes.

The inspectors met with senior licensee management to express the concem that design engineering staff had been working on a committed corrective action for eleven months without coordinating their efforts with other interrelated corrective action initiatives. The inspectors asked whether this was indicative of a broad problem in design engineering, or was an isolated incident. The licensee managers acknowledged the inspectors' concem, and were reviewing the issue at the end of the inspection period. The inspectors will track the licensee's actions to ensure that design basis changes, including those brought

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about by analysis, are property documented and communicated as an inspection follow-up item (IFl 50 266/98006-06(DRP); 50-301/98006-06(DRP)).

c.

Conclusions Offsite, corporate office-based engineering personnel working on a corrective action

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commitment initiative to assess the adequacy of a separation of seismically qualified and l

non-qualified piping systems were performing analyses and taking credit for components i

to function in a manner that may not have previously been considered in the design basis.

l The engineers had not evaluated whether such reliance rnight constitute a design basis change. Additionally, onsite licensee personnel performing concurrent and interrelated corrective action initiatives had not been informed of the potential design engineering

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activities that could have affected the results of these other initiatives.

I E3 Engineering Procedures and Documentation

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E3.1 Review of Desian Basis and Controls for 125-Volt Direct Current (Vdc) System i

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Inspection Scope (IP 37551)

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l The inspectors reviewed the design basis document and applicable battery loading L

calculations for the 125-Vdc system. The review was performed to ensure accuracy of l

the documents and verify operability of the system relative to the design basis.

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Observations and Findinas The 125-Vdc battery system is designed to provide service for one hour in the event of a i

total loss of altemating current voltage at the station (station blackout). During a review l

of this system, the inspectors asked licensee representatives to provide any additional

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documentation which may take into account battery loads added to the system since the latest master calculation was generated.

l The licensee provided the inspectors with a current listing of the master, individual l

battery, and additional equipment calculations for the 125-Vdc system. Many of the additional equipment loads were listed as evaluated but awaiting update to the goveming battery calculations.

The inspectors held a meeting with the responsible system engineer to discuss the system loads and calculations. The engineer stated to the inspectors that the process used to review modification of loads against existing calculations did not prompt the reviewer to consider other outstanding loads as the result of other modifications affecting the system, to determine the cumulative effect on the 125-Vdc system. This condition could have led to concurrent modifications not referencing appropriate updated battery loading calculations. However, the system engineer subsequently performed

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l conservative calculations from the modification documentation available to illustrate that the 125-Vdc system was operable. The process problems identified were described in

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CR 98-1528. An OD, written on April 9,1998, indicated that the system was operable.

The inspectors regarded the lack of maintaining accurate documentation of the 125-Vdc decign basis capabilities a violation (VIO 50-266/98006-07(DRP); 50-301/98006-07(DRP))

of 10 CFR Part 50 Appendix B, Criterion Ill, " Design Control," which requires that design

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changes be subject to design control measures to assure that the design basis is maintained. This problem dated back to about May 31,1995, when the calculations for the Nos.105,106, and 305 station batteries had last been updated. The inspectors reviewed the OD regarding the issues discussed above and had no further questions on

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the matter.

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Conclusions l

The inspectors concluded that tne 125-Vdc system was capable of meeting design basis

functions. However, the failure to maintain an up-to-date battery loading calculation was

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considered a violation of 10 CFR Part 50, Appendix B, Criteiion ill, " Design Control."

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E3.2 Reactor Enaineerina Update of Estimated Cribcal Rate Position Calculation a.

Inspection Scope (IPs 37551 and 71707)

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The inspectors reviewed the circumstances of the suspended critical approach on March 28,1998, discussed in Section 01.1 of this report.

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Observations and Findinas

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As discussed in Section 01.1 of this report, the first attempt to bring the Unit 2 reactor l

critical on March 28,1998, was suspended due to the licensse's identification during the

withdrawal of Control Bank "D" control rods that the reactor would become critical much earlier than anticipated based on the estimated critical rate calculation. Operations

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_ personnel followed appropriate procedures regarding this matter. The reactor critical rate

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l position was recalculated prior to a second attempt to bring the reactor critical.

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The inspectors reviewed the information regarding the first critical approach to ascertain l

why the estimated rate calculation was in error. The inspectors leamed through

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interviews of reactor engineering personnel and a review of a recent reactor engineering

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self-assessment, that the estimated critical rate position calculation procedure had been identified as needing revision. In the self-assessment report dated December 3,1997, a finding highlighted the need for obtaining accurate xenon information from a previous shutdown to ensure the accuracy of subsequent startup critical parameters. The reactor engineering organization had not implemented this recommendation prior to the restart of Unit 2. The inspectors regarded this matter as another example of a problem with reactor l

engineering performance that resulted in a previous violation (VIO 50-266/98003-02(DRP); 50-301/98003-02(DRP)).

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Conclusions l

The inspectors concluded that the reactor engineering organization provided an inadequate critical rate position procedure to operations personnel during the startup of Unit 2. Although reactor engineering personnel had previously identified problems with the procedure, timely corrective actions had not been taken. The problems revealed during the startup were considered additional examples of a previously identified problem with reactor engineering performance, for which a violation had been recently issued.

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E4 Engineering Staff Knowledge and Performance (IP 37551)

During a vertical slice review of the 125-Vdc system, the inspectors interviewed the engineer responsible for the system. The discussion involved design bases and operability considerations for the system. The engineer had been assigned to the system

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for less than one month.. Nevertheless, the inspectors noted that the engineer displayed

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clear ownership of the 125-Vdc system and conveyed a sensitivity to emerging issues affecting the system and aggressively pursued issue resolution.

E6 Engineering Organization and Administration E6.1 Conduct of the Dutv Technical Advisor Proaram a.

Inspection Scope (IPs 37551 and 71707)

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As part of the monitoring of the Unit 2 reactor startup on March 28,1998, the inspectors reviewed the implementation of the duty technical advisor (DTA) program.

b.

Observations and Findinas On the evening of March 27,1998, during the first attempt to t::ing the Unit 2 reactor critical, the inspectors noted that the DTA (a reactor engineer) also served as the startup engineer for the Unit. This individual had been the DTA for the day and was present for the critical approach which began around 2:00 a.m., on March 28,1998. The DTA had

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been called earlier in the evening to review and verify procedures and calculations for the

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l reactor startup. The inspectors queried the DTA as to his alertness and if he had an opportunity for rest earlier in the evening. The DTA indicated that he was able to get some brief rest and felt capable to oversee the reactor startup. The inspectors noted no problems regarding the DTA's performance during the subsequent startup attempt.

The inspectors noted during the second attempt to start up Unit 2 on March 28,1998, at around 2:00 p.m., that the same individual was serving as the DTA (but not as the startup engineer). The inspectors asked the DTA about the two consecutive days of work. The DTA indicated that due to a reduction in the number of qualified DTAs, consecutive days l

were occasionally required.

Concemed about the appropriateness of DTAs standing 48-hour-long watches, the inspectors reviewed the licensee's DTA program and response to NRC Generic l

Letter 86-04, " Policy Statement on Engineering Expertise on Shift." The inspectors noted that the program was approved by the NRC for DTAs to stand 24-hour watches and that i

the number of available DTAs would be sufficient for adequate rotation of DTA-qualified

. personnel. The inspectors also noted that the intent of the procedure describing l

implementation of the DTA program (Nuclear Organization Manual Duty Technical l

Advisor Procedure) was that DTAs would not serve a collateral position while functioning l

as a DTA. The inspectors acknowledged to station management that the DTA who served as the startup engineer for the first critical attempt was not the "on-call" reactor engineer and that this met the verbatim requirements of the procedure However, the

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fact that the DTA served as the startup engineer was not in accordance with the intent of

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the procedure.

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The inspectors discussed with licensee management the concems regarding DTAs serving 48-hour shifts and their fitness-for-duty to fulfill their safety-related role in response to an emergency. Licensee management indicated that oversight of the

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DTA program would be assigned to the operations department manager and that consecutive shifts would no longer be allowed. The operations manager issued an

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electronic message to all DTAs regarding this matter, following the discussion with the inspectors.'

Licensee management also indicated that this issue would be further corrected later in the year as plans were well underway to establish a shift technical advisor program which j

would be controlled by the operations department.

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. Conclusions The inspectors concluded that the practice of DTAs serving two consecutive shifts (48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />) was not consistent with the intent of program procedures and raised questions regarding the DTA's fitness-for-duty. Although the inspectors noted no associated

performance issues, licensee management immediately revised expectations to preclude

potential fitness-for-duty issues.

E8 Miscellaneous Engineering issues E8.1 (Closed) VIO 50-266/96002-05(DRP): 50-301/96002-05(DRP): Three examples were identified regarding the failure to update the FSAR as required by 10 CFR 50.71(e). The licensee revised the FSAR to address the three examples and subsequently formed an

'j interdisciplinary process improvement team to review the FSAR update process to ensure that all required changes were being identified and implemented in a timely manner. One outcome of the review was a revision of the FSAR change procedure (Nuclear Power Business Unit Procedure, NP 5.2.6, "FSAR Updates"). However, during a followup inspection of this area (IR No. 50-266/97023(DRS); 50-301/97023(DRS)), NRC inspectors identified two additional examples where the FSAR had not been revised in a timely manner and a violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action,"

was cited. The earlier violation is considered closed and the corrective actions for the failure of the previous long-term corrective actions will be reviewed as part of the more recent violation (VIO 50-266/97023-03(DRS); 50-301/97023-03(DRS)).

E8.2 (Closed) VIO 50-266/96003-04(DRP): 50-301/96003-04(DRP): Contrary to American Society of Mechanical Engineers (ASME) Code post-maintenance testing requirements, service water pump P-32E was retumed to service in December 1995 without determining a new vibration reference value or confirming the previous reference value.

This issue involved the retum of the pump to service with vibrations in the " alert" range.

In a letter to the NRC dated July 19,1996, the licensee did not agree that this issue was a violation of ASME Code requirements and did not address what actions were being taken to prevent reoccurrence of a similar problem. As discussed in a letter to the licensee from the NRC, dated October 30,1996, the licensee has taken steps to prevent recurrence.

Early in 1997, inspector review of the repair, testing, and retum-to-service of the P-32A service water pump identified that the licensee still had a misunderstanding of ASME Code reference value requirements. This misunderstanding was resolved before the

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pump was retumed to service. Subsequent NRC review of the licensee's inservice l

testing program in mid-1997 identified no additional problems with reference value requirements (Section M3.1.b.4, IR No. 50-266/97010(DRS); 50-301/97010(DRS)).

E8.3 (Closed) IFl 50-266/96006-01(DRP): 50-301/96006-01(DRP): The inspectors will review the results of the licensee's review of the inservice testing program to ensure that design basis requirements for all safety-related pumps are incorporated in IST program test i

acceptance criteria. A followup programmatic review of this issue by NRC inspectors (IR No. 50-266/96013(DRP); 50 301/96013(DRP)) did not identify any problems; howevel, the inspectors kept the IFl open pending a review of the incorporation of instrument

inaccuracies into IST acceptance criteria. In late 1996, the licensee completed

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I engineering calculations addressing the incorporation of instrument inaccuracies into the acceptance criteria. The inspectors reviewed Calculation No. 96-0233 for the

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containment spray pumps and verified that the instrument inaccuracies had been

incorporated into the pump IST acceptance criteria.

Partly because of the concems identified in the past two years by the licensee and the i

NRC, the licensee initiated an extensive rebaselining of the IST program in mid-1997.

The rebaselining effort was being conducted by a team of two full-time contractors, one part-time contractor, and the site IST program coordinator. A brief description of the i

rebaselining project was provided to the NRC in a letter dated December 12,1997, from the licensee. To date, the project has resulted in an extensive rewriting and amplification of IST background documents and the generation of numerous condition reports.

E8.4 (Closed) LER 50-266/96016: Pressurizer Safety Valve Lift Setpoint Out of Tolerance Due l

to Temperature Effects. This item was discussed and dispositioned in Sections E8.2

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and E8.3 of IR No. 50-266/98003(DRP); 50-301/98003(DRP), but the applicable LER was misidentified as LER 50-266/96014, which had previously been closed. This section corrects the administrative error (referencing the incorrect LER number) contained in IR No. 50-266/98003(DRP); 50-301/98003(DRP).

E8.5 LQlosed) LER 50-266/97021: SFP Cooling System Not in Accordance With Plant Design Basis. This item is discussed and dispositioned in Section E1.2 of this report.

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E8.6 (Closed) LER 50-266/97028: RWST Recirculation Piping not in Compliance with Plant Design Basis. This item is discussed and dispositioned in Section E1.2 of this report.

l IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Unit 1 Refuelino Outaae Radiological Controls Performance Durina This inspection Period

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(IP 71750)

The licensee had recorded 85 person-rem for the Unit 1 refueling outage at the end of the inspection period. This was on track with established goals which projected the outage personnel exposures to total about 130 person-rem. Personnel contamination events (PCEs) were much higher than anticipated with 81 recorded at the end of the inspection period. The goal for the entire outage was set at 63 PCEs. Most of the PCEs were low-l

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level contaminations (shoes); however, the health physics department was in the process of evaluating the potential causes for the higher than expected number of PCEs. The inspectors concluded that the licensee was maintaining good radiological controls for the Unit i refueling outage and an appropriate response was being undertaken to address higher than anticipated PCEs.

R7 Quality Assurance in RP&C Activities R7.1 Quality Assurance Audit of Health Physics Exit Meetina (IP 7175,0.]

The inspectors attended a quality assurance department audit exit meeting on April 6, 1998. The audit included a review of various aspects of the radiation protection program including, instrumentation controls, offsite dose calculation manual adequacies, radiation protection personnel training, and implementation of personnel dosimeter programs. The auditors identified several findings within these areas which were both administrative and performance-based. The radiation protection program manager openly discussed the findings with the auditors to gain a clear understanding of the issues. The results of this audit will be contained in audit report A-P-98-03 which was not issued at the end of the inspection period.

V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 17,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

X3 Meeting With Local Public Officials The inspectors, along with the Senior Resident inspector from the Kewaunee Nuclear Power Plant, met with local officials from the Town of Two Creeks, Kewaunee County, and Manitowoc County on Thursday April 16,1998, at the Two Creeks Town Hall in Two Creeks, Wisconsin.

The inspectors provided the officials with an overview of NRC organizations, the resident inspector program, and the inspection process. Local officials asked the inspectors questions i

regarding these matters and other aspects of the NRC, which were answered by the inspectors.

i The officials thanked the inspectors for the opportunity to meet and ask questions.

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PARTIAL LIST OF PERSONS CONTACTED Licensee Wisconsin Electric Power Company M/EPCO)

S. A. Patuiski, Site Vice President A. J. Cavia, Plant Manager (outgoing)

M. E. Reddemann, Plant Manager (incoming)

R. G. Mende, Operations Manager W. B. Fromm, Maintenance Manager J. G. Schweitzer, Site Engineering Manager R. P. Farrell, Health Physics Manager D. F. Johnson, Regulatory Services and Licensing Manager

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INSPECTION PROCEDURES USED IP 37551:

Onsite Engineering IP 40500:

Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems IP 61726:

Surveillance Observations IP 62707:

Maintenance Observations IP 71707:

Plant Operations IP 71750:

Plant Support Activities IP 92700:

Onsite Follow up of Written Reports of Noaroutine Events at Power Reactor Facilities ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-266/98006-01(DRP)

VIO Failure to follow the procedure regarding reactor operator observations of the main control panels 50-266/98006-02(DRP)

VIO Failure to follow the procedure regarding the weighing of the reactor vessel intemals lifting rig 50-301/98006-03(DRP)

NCV Failure to perform post maintenance testing prior to placing LTOP in service 50-301/98006-04(DRP)

NCV Failure tu implement corrective action regarding C-036 50-266/98006-05(DRP)

NCV Design control of seismically controlled piping 50-301/98006-05(DRP)

systems related to SFP and RWST 50-266/98006-06(DRP)

IFl Followup of design basis changes to ensure 50-301/98006-06(DRP)

proper documentation and interdepartmental I

communications l

50-266/98006-07(DRP)

VIO Failure to implement adequate design control 50-301/98006-07(DRP)

measures for 125-Vdc system calculations i

Closed l

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50-266/98004 LER Reactor coolant pump lube oil collection system 50-301/98004 design nonconformance with Appendix R Section 111.0 50-301/98002 LER Reactor coolant pump component cooling water l

retum line check valve seriously degraded

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I 50-301/95006 LER PORV post-maintenance testing not performed prior to establishing LTOP 50-301/98006-02(DRP)

NCV Failure to perform post maintenance testing prior to i

placing LTOP in service 50-266/96002-01(DRP)

IFl Scheduling and planning of work 50-301/96002-01(DRP)

50-266/97042 LER Failure to perform containment personnel air lock surveillance (

50-301/98006-03(DRP)

NCV Failure to implement corrective action regarding C-

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036 50-266/98006-04(DRP)

NCV Design control of seismically controlled piping 50-301/98006-04(DRP)

systems related to SFP and RWST l

50-266/96002-05(DRP)

VIO Licensees program weakness to update FSAR

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50-301/96002-05(DRP)

50-266/%003-04(DRP)

VIO IST Weakness - ASME Code 50-301/96003-04(DRP)

50-266/96006-01(DRP)

IFl IST Program deficiencies l

50-301/96006-01(DRP)

50-266/% 016 LER Pressurizer safety valve lift set point out of tolerance due to temperature effects 50-266/97021 LER Spent fuel pool cooling system not in accordance j

with plant design basis l

l 50-266/97028 LER Refueling water storage tank recirculation piping not l

in compliance plant design basis Discussed 50-266/97020-02(DRP)

IFl Evaluate procedure upgrade program l

50-301/97020-02(DRP)

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50-266/97006-02(DRP)

IFl Review maintenance program improvements l

50-301/97066-02(DRP)

50-266/97021-02(DRP)

VIO Failure to test containment door interlock 50-301/97021-02(DRP)

l 50-266/97023-03(DRS)

VIO Failure of corrective actions for FSAR updates 50-301/97023-03(DRS)

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l LIST OF ACRONYMS USED IN POINT BEACH REPORTS AC Altemating Current AFW Auxiliary Feedwater ASME American Society of Mechanical Engineers I

CCW Component Cooling Water CFR Code of Federal Regulations CLB Current Licensing Basis CO Control Operator CR Condition Report DOS Duty Operating Supervisor j

DRP Division of Reactor Projects DTA Duty Technical Advisors ECCS Emergency Core Cooling System

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EDG Emergency Diesel Generator l

ESF Engineered Safety Feature

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EP Emergency Planning FSAR-Final Safety Analysis Report IFl inspection Follow-up Item IP Inspection Procedure IPE Individual Plant Evaluation l

IR inspection Report lLRT Integrated Leak Rate Test IST Inservice Testing IT

'7 service Test Procedure LCO Limiting Condition for Operation LER Licensee Event Report LTOP Low Temperature Over-Pressure Protection NCV Non-Cited Violation NDE Non-Destructive Examination l

NP Nuclear Power Business Unit Procedures j

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NRC Nuclear Regulatory Commission OD Operability Determination

Operating Instruction OM Operations Manual j

OOS Out-of-Service i

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OP Operating Procedure ORT Operations Refueling Test PASS Post-accident Sampling System PCE Personnel Contamination Event POD Prompt Operability Determination

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PORV Power-Operated Relief Valve QA Quality Assurance RCP Reactor Coolant Pump RCS Reactor Coolant System RHR Residual Heat Removal RMP Routine Maintenance Procedure RP Radiation Protection RV Reactor Vessel RWST Refueling Water Storage Tank

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SE Safety Evaluation SER Safety Evaluation Report SFP Spent Fuel Pool

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SW Service Water TDAFW Turbine Driven Auxiliary Feedwater TS Technical Specification

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T/S Technical Specification Test URI Unresolved item Vdc Volt Direct Current VIO Violation VNCR Control Room Ventilation

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l S. Patuiski-2-i The violations identified above are cited in the enclosed Notice of Violation (Notice), and the j

circumstances surrounding the violations are described in detailin M e enclosed report. Please note that you are required to respond to this letter and 5:iould follow the instructions specified in the enclosed Notice when preparing your response. Tns NRC will use your response, in part, to determine whether further enforcement action is necesnary to ensure compliance with regulatory requirements.

In accordance with 10 CFR 2.790 of the NRC's " Rules of Practic'.," a copy of this letter, its enclosures, and your response will be placed in '.he NRC Public Document Room.

Sir cerely,

/s/ Marc L. Dapas for Geoffrey E. Grant, Director Division of Reactor Projects Docket Nos.: 50-266, 50-301 License Nos.: DPR-24, DPR-27 l

Enclosures:

1.

Notice of Violation 2.

Inspection Report

No. 50-266/98006(DRP);

50-301/98006(DRP)

See Attached Distribution

DOCUMENT NAME: G:\\poin\\ poi 98006.drp

To receive a copy of thle document, Indicate in the b3x "C" = Copy without attachment / enclosure "E" = Copy with attachment / enclosure

• N* = No copy

OFFICE

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NAME

Kunowski:dp /fAL JMcBp)pfg

Grant ///

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DATE

GM98

N/d98

04H95 05/05//P

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OFFICIAL RECORD COPY

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S. Patuiski

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cc w/encis:

R. R. Grigg, President and Chief

Operating Officer, WEPCO

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A. J. Cayia,' Plant Manager

B. D. Burks, P.E., Director

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- Bureau of Field Operations

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Cheryl L. Parrino, Chairman

Wisconsin Public Service

Commission

State Liaison Officer

Distribution:

CAC (E-Mail)

Project Mgr., NRR w/ encl

A. Beati w/ encl

J. Caldwell w/ encl

B. Clayton w/ encl

SRI Point Beach w/enci

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DRP w/enci

)

TSS w/enct

DRS (2) w/encI

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Rill PRR w/enci

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PUBLIC IE-01 wienc!

Docket File w/enci

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GREENS

LEO (E-Mail)

DOCDESK (E-Mail)

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