ML993540187

IRC Brunswick 1999007 Integrated

ML993540187
Person / Time
Issue date:	11/22/1999
From:	Division Reactor Projects II
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UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II Carolina Power and Light Company ATTN: Mr. J. S. Keenan Vice President Brunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461

SUBJECT:

NRC INTEGRATED INSPECTION REPORT NOS. 50-325/99-07, AND 50-324/99-07

Dear Mr. Keenan:

This refers to the inspection conducted on September 12 through October 23, 1999, at the Brunswick reactor facility. The enclosed report presents the results of this inspection.

Based on the results of this inspection, the NRC has determined that one violation of NRC requirements occurred. This violation is being treated as a Non-Cited Violation (NCV),

consistent with Section VII.B.1 of the Enforcement Policy. This NCV is described in the subject inspection report. If you contest the violation or its severity level, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II, and the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001.

CP&L 2

In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter and its enclosures will be placed in the NRC Public Document Room (PDR).

Sincerely, (Original signed by B. R. Bonser)

Brian R. Bonser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

(See page 2)

CP&L 3

Enclosure:

Integrated NRC Inspection Report cc w/encl:

J. J. Lyash, Director Site Operations Brunswick Steam Electric Plant Carolina Power & Light Electronic Mail Distribution Terry C. Morton, Manager Performance Evaluation and Regulatory Affairs CPB 7 Carolina Power & Light Company Electronic Mail Distribution K. R. Jury, Manager Regulatory Affairs Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail Distribution William D. Johnson Vice President & Corporate Secretary Carolina Power and Light Company Electronic Mail Distribution John H. O'Neill, Jr.

Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128 Mel Fry, Director Division of Radiation Protection N. C. Department of Environment and Natural Resources Electronic Mail Distribution Peggy Force Assistant Attorney General State of North Carolina Electronic Mail Distribution Robert P. Gruber Executive Director Public Staff NCUC P. O. Box 29520 Raleigh, NC 27626-0520 Public Service Commission State of South Carolina P. O. Box 11649 Columbia, SC 29211 Jo Ann Simmons, Chairman Brunswick County Board of Commissioners P. O. Box 249 Bolivia, NC 28422 Dan E. Summers Emergency Management Coordinator New Hanover County Department of Emergency Management P. O. Box 1525 Wilmington, NC 28402 Distribution w/encl: (See page 3)

CP&L 4

Distribution w/encl:

A. Hansen, NRR PUBLIC OFFICE DRP/RII DRP/RII DRP/RII DRP/RII DRS/RII DRS/RII SIGNATURE GWest:vyg TEaslick EBrown GGuthrie GWiseman WBearden NAME DATE 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 E-MAIL COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICIAL RECORD COPY DOCUMENT NAME: G:\\Brunswick\\REPORT\\IR 9907 Draft.wpd

Enclosure U. S. NUCLEAR REGULATORY COMMISSION REGION II Docket Nos:

50-325, 50-324 License Nos:

DPR-71, DPR-62 Report No:

50-325/99-07, 50-324/99-07 Licensee:

Carolina Power & Light (CP&L)

Facility:

Brunswick Steam Electric Plant, Units 1 & 2 Location:

8470 River Road SE Southport, NC 28461 Dates:

September 12 to October 23, 1999 Inspectors:

T. Easlick, Senior Resident Inspector E. Brown, Resident Inspector E. Guthrie, Resident Inspector G. Wiseman, Reactor Inspector (Sections M2.1, F3.1, F3.2, F3.3, F7.1, and F8.1)

W. Bearden, Reactor Inspector (Sections O5.1, M1.3, M2.1 and F3.1)

Approved by:

B. Bonser, Chief, Projects Branch 4 Division of Reactor Projects

EXECUTIVE

SUMMARY

Brunswick Steam Electric Plant, Units 1 & 2 NRC Inspection Report 50-325/99-07, 50-324/99-07 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection; in addition, it includes the results of a fire protection inspection by regional inspectors.

Operations A violation with two examples was identified for failures to follow plant procedures during a Unit 2 startup. These failures resulted in a Group 1 primary containment isolation system actuation and a subsequent manual scram. A weakness was identified concerning operator workarounds that were placed in operating procedures to compensate for equipment deficiencies. In two examples, plant deficiencies were not properly addressed and the licensee used proceduralized operator workarounds to correct the impact of the deficiencies on plant operations (Section O1.1).

A detailed walkdown of the standby gas treatment (SBGT) system indicated that it was well-maintained and able to perform its intended safety function. General housekeeping in the area of the SBGT trains was excellent and support systems were functioning as expected. The system engineer was very knowledgeable and current on all issues affecting the SBGT system (Section O1.3).

The adequacy of licensed operator alternate safe shutdown (ASSD) training and the quality of supporting materials was very good. The use of photographic representations of plant equipment during performance of procedure steps was an effective and efficient method of providing classroom training (Section O5.1).

Maintenance Maintenance activities included effective supervisory oversight, were performed consistent with the applicable procedures, and utilized test equipment that was within its current calibration cycle. Technicians were knowledgeable of the evolutions and expected instrument responses and used satisfactory three-part communications (Section M1.1).

Observed maintenance on the Unit 2 notch override/emergency rod in switch following a control rod mispositioning event on September 26 found no deficiencies with the maintenance activities or paperwork. The reactor manual control system intermittent malfunction troubleshooting was enhanced by the use of the licensees Operational Experience program (Section M1.2).

The Maintenance Rule expert panel meeting discussions on covered topics were thorough and productive. The bases for all decisions were logical, risk-informed, and well-documented (Section M1.3).

The material condition and general housekeeping for ASSD equipment was good. The inspectors identified no safety concerns as a result of walkdowns of ASSD equipment (Section M2.1).

Engineering In general, troubleshooting instructions provided an adequate description of activities and possible operational affects. However, several troubleshooting activities were identified where the possible operational affects were not fully addressed by engineering. The licensee indicated that reinforcement of the expectations for the content of troubleshooting instructions would be provided to appropriate plant personnel (Section E4.1).

Plant Support The licensee identified through routine chemistry sampling that for several months the boron concentration in the Unit 1 reactor coolant had been increasing. A review team consisting of members of chemistry, engineering, operations, nuclear fuels, and outage and scheduling determined that the most likely source of the boron was a leaking control blade. The licensees staff conducted a comprehensive and thorough review of the issue, which resulted in an adequate corrective action plan (Section R2.1).

The licensees preparations for Hurricane Floyd and activities during and after the storm were timely, comprehensive, and appropriate. Actions following the storm were also appropriate (Section P1.1).

No discrepancies were noted during the review of plant ASSD and fire protection procedures. Plant procedures provided sufficiently detailed guidance for operator actions to safely shut down the plant in the event of a loss of control room habitability (Section F3.1).

The maintenance inspection and surveillance test program for the emergency 8-hour battery-powered lighting system was sufficient to ensure that the system design function was met. The emergency lighting units were operational and the lighting heads were aimed to provide adequate illumination to perform the required shutdown actions denoted in ASSD procedures (Section F3.2).

The surveillance test program for the ASSD sound-powered phone system was sufficient to verify proper operation of the system. The sound-powered phone jacks were installed at the proper locations to support required shutdown actions identified in the ASSD procedures (Section F3.3).

Licensee personnel failed to correctly identify that a missing temperature switch affected the operability of the EDFP and to correct this condition. As a result of this failure, licensee personnel subsequently allowed the MDFP to be removed from service for maintenance. With both pumps concurrently inoperable for approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />, the licensees ability to mitigate a fire was severely degraded due to the unavailability of other means to provide water fire suppression. This condition put the plant outside of

the fire protection design basis. A URI was initiated to further review the licensees risk analysis and to determine the potential consequences of a fire should one have occurred during the concurrent pump inoperability (Section F4.1).

The fire protection program upgrade (FPPU) project meeting discussions on the status task actions for the FPPU Part 2 work-off schedule were well-coordinated and productive. Completion of corrective actions associated with the upgrade project continued to be progressing on schedule. Management attention to the site fire protection program was effective in ensuring proper prioritization of work assignments and scheduling of FPPU project action items (Section F7.1).

Report Details Summary of Plant Status Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On September 15, the unit was shut down for Hurricane Floyd preparations. Unit 1 startup activities were commenced on September 19 and the reactor was taken critical on that date.

Unit 1 RTP was limited by procedure due to the unavailability of one offsite power source. The unit was returned to 100 percent RTP on October 2.

Unit 2 began the report period operating at 100 percent RTP. On September 15, the unit was shut down for Hurricane Floyd preparations. Unit 2 startup activities were commenced on September 19 and the reactor was taken critical on that date. During startup activities on September 20, the unit was manually scrammed following a main steam isolation valve automatic closure event. The plant was restarted later that same day. Unit 2 RTP was limited by procedure due to the unavailability of one offsite power source. The unit was returned to 100 percent RTP on October 2.

I. Operations O1 Conduct of Operations O1.1 Unit 2 Group 1 Isolation and Manual Reactor Scram

a.

Inspection Scope (71707, 37551)

At 12:09 a.m., on September 20, with Unit 2 in Mode 2 (startup) and operating at approximately four percent RTP, control room operators received alarms and instrument indications of a Group 1 primary containment isolation system (PCIS) actuation.

Subsequent activities to recover from the closure of the main steam isolation valves (MSIVs) and continued startup activities resulted in a higher-than-expected reactor power increase and the insertion of a manual reactor scram. The inspectors reviewed the following to determine the sequence of events and proper plant operations:

plant computer transient data including plant transient traces, operator event logs, licensees post-event trip review, licensees root cause investigation including corrective actions, and plant personnel statements and interviews with operators.

b.

Observations and Findings On September 20, Unit 2 was at approximately four percent RTP and 450 pounds per square inch gauge (psig) in the process of pressurizing up to rated pressure. The Unit

2 senior control operator (SCO) was directing activities in accordance with General Plant Operating Procedure 0GP-02, Approach to Criticality and Pressurization of the Reactor, Revision (Rev.) 65. At 12:09 a.m., the operators received a Group 1 PCIS actuation that closed the MSIVs, causing reactor pressure to increase rapidly to a peak of approximately 1030 psig and then stabilize at 950 psig as a result of the reactor operator inserting control rods to reduce power. Additionally, the operating reactor feedwater pump (RFP) tripped on high reactor water level, which resulted in a loss of high pressure feedwater (FW) to the reactor vessel. The rapid increase in reactor pressure caused the reactor coolant temperature to increase at a maximum rate of 121 degrees Fahrenheit (ºF) per hour, which exceeded the Technical Specification (TS) limiting condition for operation (LCO) 3.4.9 limit of 100ºF per hour. The Unit 2 SCO then directed equalization around the MSIVs using an operator instructional aid called a hard card in order to control reactor pressure and water level. Following the opening of the MSIVs, the 2A RFP was placed in service and the startup level control valve was used to control reactor vessel water level. Due to voiding in the FW lines, relatively cool water was injected into the reactor vessel in a short amount of time. This cooler FW caused a rapid increase in power due to the reactivity addition and the operators responded by inserting a manual scram signal to shut down the reactor. These events were reported to the NRC in accordance with 10 CFR 50.73 on October 20, and are discussed in Licensee Event Report (LER) 50-324/1999-008-00.

The inspectors reviewed the operators actions for this event and identified two examples of procedural non-compliance. The first example concerned procedure 0GP-02, which stated in a note in Step 5.3.43, [p]rior to placing the low condenser vacuum bypass switches to normal, the pressure sensing lines should be vacuum dragged to the condenser. The actions stated in the note were performed out of sequence and the vacuum bypass switches were placed in NORMAL before the auxiliary operator (AO) vacuum dragged the sensing lines. This action caused the false condenser low vacuum signal that initiated the Group 1 isolation and closed the MSIVs. The licensee has revised 0GP-02 to include discrete steps to ensure that the Unit 2 low condenser vacuum bypass switches are in the BYPASS position prior to draining the instrument lines.

The second example of a procedural non-compliance occurred during the recovery activities from the MSIV isolation. The SCO conferred with the shift superintendent (SS) and directed the operators to equalize around and open the MSIVs. In order to perform these actions, the low condenser vacuum bypass switches needed to be placed in the BYPASS position because there was an actual low condenser vacuum condition at the time. With reactor pressure greater than 500 psig (approximately 950 psig), the SCO, after discussions with the SS, directed the operator to place the bypass switches in BYPASS, contrary to the requirements of 0GP-02, Step 5.3.44, Caution, and Operating Procedure 2OP-25, Main Steam System Operating Procedure, Rev. 43, Step 5.2.2, Caution. Additionally, the hard card, which was developed using the operating procedure for equalization around the MSIVs, stated that [i]f not in mode 1 or 2 and condenser vacuum is low, place condenser vacuum bypass switches to BYPASS.

At the time of recovery activities, the plant was in Mode 2. Following interviews with the SS and SCO, the inspectors noted that they did not refer to the plant operating procedures when the direction was given to place the bypass switches in the BYPASS position with reactor vessel pressure greater than 500 psig - only the TS was reviewed

prior to giving this direction. In this case, the failure to refer to the operating procedures resulted in the improper opening of the MSIVs under these conditions. The SS and the SCO involved with this event have been coached by the licensee regarding procedural adherence and the need for ensuring adequate communications skills regarding crew interaction.

TS 5.4.1.a requires that written procedures shall be established, implemented, and maintained covering activities which are recommended in Regulatory Guide 1.33, Appendix A, November 1972, for general plant operating procedures covering startup-cold to hot, and procedures for operating the main steam system. The failures to implement General Plant Operating Procedure 0GP-02, Step 5.3.43, Note, in one case and Step 5.3.44, Caution, and Operating Procedure 2OP-25, Step 5.2.2, Caution, in another, constitute two examples of a violation of TS 5.4.1.a. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Section VII.B.1 of the NRC Enforcement Policy. This violation is identified in the licensees corrective action program as Condition Report (CR) 99-02390, Reactor Manual Scram. This violation is identified as NCV 50-324/99-07-01, Startup Procedure Noncompliances.

In addition, a weakness was identified by the inspectors concerning operator workarounds that were placed in operating procedures as a result of equipment deficiencies. The first example was in the 0GP-02 note concerning vacuum dragging the pressure sensing lines. This action was done to correct a historical problem with condensate filling the pressure sensing lines during shutdown periods. The suspected plant deficiency that caused the condensate to fill the sensing lines was handled via an operator workaround. The failure to properly perform this workaround caused the Group 1 isolation.

Another example of a proceduralized workaround was identified in Operating Procedure 2OP-26, Turbine System Operating Procedure, Rev. 82, step 5.2.2.21 Caution, which stated, in part, Feedwater Heater Extraction Steam Valve leakage during Turbine Shell Warming could cause severe water hammer on drain lines. Shell pressure of greater than 20 psig and tracking with Turbine 1st stage or MSR shell pressure indicate valve leakage. During this event, a contributor to the void formation in the FW line following the loss of FW, was the leakage exhibited by the 4A FW level control valve. The pressure in the shell side of the 4A FW heater reached 40 psig due to leakage from the extraction steam isolation valve. In this case, the cause of the extraction steam valve leakage was also handled with an operator workaround to correct the effect of the plant deficiency. As part of the licensees corrective actions for this issue, an evaluation of other institutionalized workarounds as error precursors will be performed with lessons-learned from this event.

The licensees review of this event indicated that the reactor coolant system TS temperature restrictions had been exceeded. The restriction exceeded was the 100 ºF per hour heatup limit, which occurred immediately following the Group 1 isolation as reactor pressure rapidly increased. The temperature increased at a maximum rate of 121 ºF per hour for approximately 15 minutes until the operators inserted control rods to reduce reactor power and control the pressure buildup. This heatup rate was contrary to surveillance requirement 3.4.9.1. TS LCO 3.4.9, condition a, stated that if the requirements of the LCO were not met, the parameter was to be restored to within limits

in less than 30 minutes. Since the heatup limit was restored within that time, no TS requirements were violated. TS LCO 3.4.9.a also included the requirement to perform an evaluation to verify that the reactor coolant system was acceptable for continued operation. The inspectors verified that the evaluation was completed and that structural integrity was maintained.

c.

Conclusions A violation with two examples was identified for failures to follow plant procedures during a Unit 2 startup. These failures resulted in a Group 1 primary containment isolation system actuation and a subsequent manual scram. A weakness was identified concerning operator workarounds that were placed in operating procedures to compensate for equipment deficiencies. In two examples, plant deficiencies were not properly addressed and the licensee used proceduralized operator workarounds to correct the impact of the deficiencies on plant operations.

O1.2 Auxiliary Operator (AO) Walkaround (71707)

On October 21, the inspectors observed the Unit 1 AO conduct a reactor building tour and logtaking activities. The inspectors noted that the operator recorded plant parameters and observed equipment condition and performance as required by plant procedures. The inspectors found that the AOs tour was thorough and observant.

The inspectors noted no significant deficiencies with the observed portion of the AO building tour or logtaking.

O1.3 Standby Gas Treatment (SBGT) System Walkdown (71707)

On October 20, the inspectors conducted a detailed walkdown of accessible mechanical and electrical components of the SBGT engineered safety feature system. The inspectors reviewed the TS, updated final safety analysis report, design basis documents, and operating and surveillance procedures. The inspectors verified system valve and electrical lineups, reviewed the system standby alignment, and observed system instrumentation. All instruments indicated expected values and were calibrated.

The inspectors concluded, based on the reviews and observations stated above, that the system was in a standby readiness state and able to perform its intended safety function. General housekeeping in the area of the SBGT trains was excellent and support systems were functioning as expected. There were no equipment conditions or items that could degrade system performance. The inspectors discussed the system readiness with the system engineer and found that he was very knowledgeable and current on all issues affecting the SBGT system. Specifically, NRC Generic Letter (GL) 99-02, Laboratory Testing of Nuclear-Grade Activated Charcoal, was discussed and the inspectors noted that the system engineer was aware of the issues and was currently working on the licensees response to the GL. The licensees response will include an amendment request to reference the latest testing standards.

O5 Operator Training and Qualification O5.1 Alternate Safe Shutdown (ASSD) Training

a.

Inspection Scope (64704)

The inspectors examined portions of ongoing licensed operator (LOP) training associated with ASSD procedures for senior reactor operator (SRO) and reactor operator (RO) personnel. This examination included review of ASSD procedures and observation of a classroom exercise simulating the shutdown of both units from outside of the control room with procedure ASSD-02, Control Building, Rev. 28.

b.

Observations and Findings During review of RO and SRO classroom training, the inspectors noted that significant efforts had been made by the site training staff to produce digital photographic representations of actual control, switchgear, and motor control center (MCC) panels, and to integrate these photographs into the relevant procedure steps to enhance the quality of the training. The inspectors found that the use of these photographic representations during performance of procedure steps was an effective and efficient method of providing classroom training. In addition, the level of detail concerning procedural requirements, expectations for operator actions, and locations of equipment required for safe shutdown was acceptable. Each SRO and RO was required to participate in the classroom exercise. The inspectors concluded that the adequacy of training and quality of supporting materials was very good.

c.

Conclusions The adequacy of LOP ASSD training and the quality of supporting materials was very good. The use of photographic representations of plant equipment during performance of procedure steps was an effective and efficient method of providing classroom training.

O6 Operations Organization and Administration O6.1 Review of Institute of Nuclear Power Operations (INPO) Interim Report (71707)

The inspectors reviewed the INPO interim report dated May 3, 1999. The INPO evaluation was conducted during the weeks of March 15 and 22, 1999. The licensees response to the findings in this report were due to INPO within 6 months of the letter date. The inspectors found that the report contained no safety issues that required immediate NRC attention and that it was consistent with the NRCs current perception of licensee performance.

O8 Miscellaneous Operations Issues (90712)

O8.1 (Closed) LER 50-324/1998-004-00: High Pressure Coolant Injection System Rendered Inoperable. On December 16, 1998, the high pressure coolant injection (HPCI) system was unknowingly rendered inoperable for several hours when the system turbine exhaust vacuum breakers were shut to conduct maintenance. The TS allowed outage time for HPCI was 7 days. All other emergency core cooling systems were available during the time the HPCI system was inoperable. The safety significance of this event was minimal because the HPCI system would have injected as required. However, with the vacuum breakers shut, the potential for water hammer existed on the turbine exhaust piping should the HPCI system have been operated and then shut down. The inspectors reviewed the event investigation and found it to be thorough. The licensee determined that the root cause of the event was that changes to the original maintenance schedule were made without questioning the schedule originators. The personnel who changed the maintenance schedule were unaware that shutting the system turbine exhaust vacuum breakers would render HPCI inoperable. The investigation determined that several barriers established to prevent such events had failed. The licensee generated lessons-learned documentation which was reviewed by appropriate personnel. In addition, updates were made to improve the clarity of the appropriate design basis documents for the turbine exhaust vacuum breakers.

O8.2 (Closed) LER 50-325(324)/1999-008-00: Electric Motor Driven and Diesel Driven Fire Pump Concurrent Inoperability. This issue was reviewed by the inspectors as described in Section F4.1. An Unresolved Item (URI) was initiated pending further NRC review.

II. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities (61726, 71707)

The inspectors reviewed all or portions of the following surveillance tests:

Maintenance Surveillance Test 0MST-PCIS29Q, PCIS Reactor Water LL2 and LL3 Div II Trip Unit Channel Calibration and Functional Test, Rev. 1; and, Maintenance Surveillance Test 1MST-RCIC22Q, RCIC Steam Line Low Pressure Instrument Channel Calibration, Rev. 7.

The inspectors attended pre-job briefings for one of the surveillance tests. The participants in the briefings discussed human error precursors, verified that no other testing that could interfere with the activities was in progress, and provided a forum for any questions. During the maintenance activities, effective supervisory oversight was present, procedures used were of the proper revision, and test equipment was within its current calibration cycle. Technicians were knowledgeable of the evolutions and

expected instrument responses and used satisfactory three-part communications. The testing was completed satisfactorily in accordance with TS.

M1.2 Reactor Manual Control System (RMCS) Maintenance and Troubleshooting

a.

Inspection Scope (62707)

The inspectors observed maintenance and troubleshooting activities on the RMCS following a control rod mispositioning event.

b.

Observations and Findings On September 28 and 29, the inspectors observed the replacement of the Unit 2 notch override/emergency rod in (RONOR) switch. The inspectors attended the pre-job briefing and noted that all of the appropriate personnel were in attendance and that the necessary items were covered to ensure the success of the maintenance, including contingencies if something went wrong. The inspectors found that the maintenance and the post-maintenance testing were conducted according to procedures. No deficiencies were observed during the maintenance or found during paperwork review. The RONOR switch was replaced to troubleshoot a control rod that moved in the inward direction with the withdrawal switches actuated on September 26. The RONOR switch was taken apart to determine if the rotation stop mechanisms were broken or mispositioned; however, no deficiencies were found by the licensee.

The inspectors discussed the rod mispositioning event with the operators and found that the appropriate actions were taken. A thorough review of the circuit prints determined that any of several intermittent malfunctions could have occurred which would have caused the rod to move in the opposite direction as desired. The inspectors verified that reactor safety was not compromised as a result of this control rod mispositioning.

On October 10, another control rod moved in the inward direction during a withdrawal signal. On October 18, the licensee replaced four relays located inside the RMCS solid state timer. The licensee found through their Operational Experience program that another facility had similar problems with their RMCS and that the problem was caused by a voltage transient induced by contact arcing within the sequence timer circuit relays.

The RMCS was tested satisfactorily following the relay replacement and will be tested further when control rod testing is performed early in the next inspection period.

c.

Conclusions Observed maintenance on the Unit 2 RONOR switch following a control rod mispositioning event on September 26 found no deficiencies with the maintenance activities or paperwork. The RMCS intermittent malfunction troubleshooting was enhanced by the use of the licensees Operational Experience program.

M1.3 Maintenance Rule (MR) Expert Panel

a.

Inspection Scope (62706)

The inspectors observed the licensees MR expert panel meeting on September 29, which was conducted to review and approve goals and corrective actions for ASSD local panel control switch failures. Additionally, the inspectors reviewed previous expert panel activities associated with the emergency lighting system. The expert panel's responsibilities include the authority for decisions regarding MR goal-setting, corrective actions, and changing the MR classification of systems based on system performance.

b.

Observations and Findings The expert panel reviewed the status of corrective actions for repeated ASSD local panel control switch functional failures, which had resulted in classification of these switches as (a)(1) under the MR (10 CFR 50.65). Two local panel control switch failures had been identified during functional testing and CR 99-00099 had been issued to document the licensees evaluation of this problem. The licensee had determined that the failures occurred due to dirty contacts resulting from a lack of preventive maintenance (PM). Based on industry operating experience and vendor recommendations for inspection and cleaning, the MR expert panel established a PM activity to require routine cleaning of these switch contacts. The inspectors noted a good discussion of the issues raised. The meeting minute inputs were reviewed as each issue was completed. The bases for all decisions were well documented.

The inspectors also reviewed meeting minutes for previous expert panel meetings that had been conducted to review and approve MR monitoring activities associated with the ASSD emergency lighting system. The licensee had placed this system in (a)(1) status (an increased monitoring standard applied to systems exhibiting performance below expectations) under the MR due to repeated functional failures of individual emergency lights; CR 98-00134 had been issued to document the licensees evaluation of this problem. The licensee subsequently changed the method of testing the lights and replaced lighting batteries with a new type of battery. These actions resulted in some system performance improvement. However, some failures still occurred and the licensee has continued monitoring the system under (a)(1) status. The inspectors noted that the expert panel had been proactive in requiring the system engineer to obtain additional industry information related to performance criteria of the lighting batteries.

Goals and planned corrective actions established by the licensee were adequate.

c.

Conclusions The MR expert panel meeting discussions on covered topics were thorough and productive. The bases for all decisions were logical, risk-informed, and well-documented.

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 ASSD Material Condition Walkdowns

a.

Inspection Scope (62706)

The inspectors performed walkdowns and observed the material condition of selected portions of the following ASSD systems and plant areas:

Unit 2 Remote Shutdown Panel (RSDP)

Service Water Building Diesel Generator Building E2 Switchgear Room E4 Switchgear Room 2XA MCC 2XB MCC Emergency Diesel Generator (EDG) Switchgear

b.

Observations and Findings The material condition of inspected systems and structures was good. Piping, components, and structures were clean, painted, and had very few indications of corrosion, oil leaks, or water leaks. In addition, general housekeeping in the observed plant areas was effective.

During the walkdown of the Unit 2 RSDP, MCC 2XA, and MCC 2XB, the inspectors verified that all motor breakers were in the proper prefire rackout positions as required by Sections 3.7.1 and 3.7.2 of Operating Procedure 2OP-17, Residual Heat Removal System Operating Procedure, Rev. 120. BSEP Safe Shutdown Analysis Report, BNP-E-9.004, required that these electrical breakers and other breakers be in the off position to prevent spurious operation of valves that have the potential to cause an uncontrolled or unrecoverable loss of primary coolant or to allow service water injection into the suppression pool or reactor vessel. No problems were identified with the material condition of the Unit 2 RSDP, MCC 2XA, or MCC 2XB.

During the walkdown of the EDG switchgear and service water system switchgear, the inspectors identified inconsistent labeling on some equipment that must be operated in support of procedure ASSD-02. Guidelines contained in procedure ASSD-00, Users Guide, Rev. 21, Section 17.0, state that certain ASSD equipment should be identified by a white label with red ASSD letters. The inspectors noted that labeling on the EDG control panels was clear and in accordance with these guidelines. However, some minor labeling inconsistencies were identified on the E2 and E4 switchgears by the inspectors and promptly corrected by the licensee.

The inspectors verified that various service water valves located in the lower portion of the service water building were properly equipped with durable identification tags to support ASSD operations. Guidelines contained in Section 17.1.5 of ASSD-00 stated

that valves requiring manual operation after being in a fire area should be tagged with a durable label.

c.

Conclusions The material condition and general housekeeping for ASSD equipment was good. The inspectors identified no safety concerns as a result of walkdowns of ASSD equipment.

III. Engineering E4 Engineering Knowledge and Performance E4.1 Troubleshooting

a.

Inspection Scope (37551, 62707)

The inspectors reviewed the planning and performance of recent troubleshooting activities.

b.

Observations and Findings The inspectors reviewed several troubleshooting activities. Administrative Instruction 0AI-117, Guidance For Troubleshooting Safety Related Equipment, Rev.3, provided that the troubleshooting plan, whether in a work request/job order (WR/JO) or the attachment to the procedure, include the expected indications and impact on plant operations. This should have included a discussion of any expected or possible isolations, trips, scrams, system indications, personnel safety concerns, or TS impact.

The inspectors reviewed several troubleshooting activities and their associated piping and wiring diagrams, work tickets, and procedures. In addition, the inspectors discussed planning of troubleshooting activities with members of the maintenance and engineering organizations. Generally, the inspectors found that the instructions, in either the work ticket or the attachment to 0AI-117, provided an adequate description of the troubleshooting activities and the possible operational affects. However, the inspectors noted several instances where the scope of the instructions was not comprehensive. In one instance, the inspectors noted that troubleshooting activities to locate a ground on the 1B battery bus had progressed to the HPCI system logic. During review of the associated WR/JO, the inspectors noted that expected results, potential operational impacts, and necessary contingencies for HPCI system logic testing had not been discussed nor identified.

The inspectors also determined that the potential changes to the plant configuration in the course of troubleshooting activities had not been identified nor reviewed for the possibility of an unreviewed safety question. The WR/JO was subsequently rejected by operations and additional operational information was provided by engineering addressing the outstanding safety issues. In discussions with the licensee, the inspectors were informed that the content of a work ticket should have been consistent with the requirements of 0AI-117. The licensee indicated that reinforcement of the

expectations for planning of troubleshooting activities would be provided to appropriate plant personnel.

c.

Conclusion In general, troubleshooting instructions provided an adequate description of activities and possible operational affects. However, several troubleshooting activities were identified where the possible operational affects were not fully addressed by engineering. The licensee indicated that reinforcement of the expectations for the content of troubleshooting instructions would be provided to appropriate plant personnel.

IV. Plant Support R2 Status of RP&C Facilities and Equipment R2.1 Elevated Boron Concentration in the Unit 1 Reactor Coolant (71750, 37551)

In September 1999, the licensee determined through routine chemistry sampling that the boron concentration in the Unit 1 reactor coolant had been increasing. Concentration levels increased from the normal operating levels of 50-100 parts per billion (ppb) to 350-400 ppb. At the end of the inspection period, the level was constant due in part to the chemistry department increasing the frequency for changing the reactor water cleanup resin from monthly to every 2 weeks. The licensees nuclear fuels group evaluated the effect of boron on the reactor shutdown margin and overall operations, and after discussions with the inspectors, determined that concentration levels exceeding 7000 ppb would be required before an effect on shutdown margin could be seen.

The inspectors reviewed the licensees action plan associated with this issue and attended management briefings as the plan was developed. The licensee put together a review team consisting of members of chemistry, engineering, operations, nuclear fuels, and outage and scheduling. The team determined the possible source of the boron intrusion and provided operational guidance to deal with the problem. The team concluded that the most likely source of the boron was a leaking control blade.

Engineering determined that the leaking blade was probably an older blade used in one of the 25 control cell locations in the core. Blades in the control cell location are normally used during the operating cycles to control and shape reactor power. There are three control blades that currently fit this description, which the licensee plans to remove during the next Unit 1 refueling outage in March 2000. The plan to remove these blades will be incorporated into the current control blade shuffle and discharge plan for the upcoming outage. The inspectors concluded that the licensees staff conducted a comprehensive and thorough review of the issue, which resulted in an adequate corrective action plan.

P1 Conduct of EP Activities P1.1 Hurricane Floyd

a.

Inspection Scope (71750, 93702)

The inspectors monitored licensee activities associated with Hurricane Floyd.

b.

Observations and Findings The site declared a Notification of Unusual Event (NOUE) at 11:10 p.m., on September 14 following the issuance of a hurricane warning by the National Weather Service for southeastern North Carolina. Floyd was a category II hurricane with the eye of the hurricane passing directly over the site. The licensee activated their Technical Support Center (TSC) and Emergency Operations Facility on September 14. The inspectors observed licensee activities from the TSC and the control room throughout the activation period. Both units were taken to cold shutdown due to the impending threat of hurricane-force winds onsite. The units responded normally during the shutdown activities. The plant remained connected to off-site power throughout the storm so the emergency diesel generators were not used. The NOUE was terminated on September 16 at 1:30 p.m.

Thirty-two out of thirty-five total emergency sirens were rendered inoperable by the storm. All of the sirens were repaired prior to restarting the units. Damage to the southwest side of the turbine building occurred during the storm. Hurricane-force winds tore panels off the building, exposing the interior of the building to the environment. The building internal atmosphere was continuously monitored for radiation during this time and no abnormal readings were detected. The building was repaired and tested for leak-tightness prior to restarting the units. The inspectors did not observe any other significant damage to the site caused by the hurricane. Direct current (DC) grounds on site safety-related battery systems occurred during the storm and were a challenge to find for the licensee. This issue was previously identified as Inspection Followup Item (IFI) 50-325(324)/98-08-02, Review Licensee Actions to Resolve DC Ground Problems, following Hurricane Bonnie in August 1998. Grounds on Unit 1 had not stabilized at normal levels by the close of the inspection period. The IFI remains open until corrective actions are completed by the licensee.

Many of the roads in the emergency planning zone for the site were blocked following the hurricane due to flooding. Evacuation routes were verified passable prior to the approval for restart of the units to ensure guidelines of the site Emergency Plan were met. Following coordination between the Federal Emergency Management Agency (FEMA) and the NRC, permission to restart the units was given on September 18. The units were started up and taken critical on September 19 and September 20.

c.

Conclusions The licensees preparations for Hurricane Floyd and activities during and after the storm were timely, comprehensive, and appropriate. Actions following the storm were also appropriate.

F3 Fire Protection Procedures and Documentation F3.1 Review of ASSD and Fire Protection Procedures

a.

Inspection Scope (64704)

The inspectors reviewed upgraded ASSD and Fire Protection procedures. Additionally, a plant tour was performed to verify that one ASSD procedure reflected as-built plant conditions.

b.

Observations and Findings The inspectors reviewed portions of the following plant procedures:

ASSD-00, Users Guide, Rev. 21 ASSD-01, Alternate Safe Shutdown Procedure Index, Rev. 20 ASSD-02, Control Building, Rev. 28 0PLP-01.2, Fire Protection System Operability, Action, and Surveillance Requirements, Rev. 15 0PLP-01.5, Alternate Shutdown Capability Controls, Rev. 10 No discrepancies were noted during the review of the above procedures.

During the plant tour, the inspectors compared Sections E, F, and G of procedure ASSD-02 with actual plant layout and conditions. The inspectors determined that the procedure provided sufficiently detailed guidance for operator actions to: transfer control of safe shutdown equipment from the control room to the RSDP; perform the required EDG 4kV switchgear breaker alignment; and align and operate the service water system.

c.

Conclusions No discrepancies were noted during the review of plant ASSD and fire protection procedures. Plant procedures provided sufficiently detailed guidance for operator actions to safely shut down the plant in the event of a loss of control room habitability.

F3.2 Review of 10 CFR 50, Appendix R, Section III.J., Emergency Lighting

a.

Inspection Scope (64704)

The inspectors reviewed the design, operation, and surveillance inspection and testing of the 8-hour battery-powered emergency lighting system.

b.

Observations and Findings The inspectors review of upgraded procedures OPT-34.13.3.0, Battery Powered Emergency Lighting Units Inspection," Rev. 13 and OPT-34.5.9.1, Battery Powered Emergency Lighting Units Functional Test," Rev. 20, as well as discussions with the facility fire protection engineer, indicated that the scope and content of the maintenance inspection and periodic test procedures were sufficient to verify the performance of the battery-powered emergency lighting system. The procedures were well-written and verified that the emergency lighting units batteries were adequately sized, and that lighting heads were aimed in accordance with the lighting drawings.

The inspectors walked down the remote shutdown equipment identified in procedure ASSD-02 in the Unit 2 reactor building, diesel building, and service water building and inspected approximately 25 lighting units. The purpose of the walkdown was to verify that the emergency lighting unit lamps were operational and that the lighting heads were aimed to provide adequate illumination to perform the required shutdown actions denoted in the ASSD procedure. During the walkdown of the service water building, the inspectors questioned the adequacy of illumination provided by emergency lighting for reading the service water system pressure indicators for Units 1 & 2 (PI-SW-145). No emergency lamps were aimed directly toward the indicator gauges and a vertical conduit seismic support was installed near the Unit 2 indicator, partially obstructing the view of the face of the pressure indicator gauge. In response to the inspectors concerns, the licensee verified that the actions required in the ASSD procedure for monitoring the service water pressure at pressure indicators 1 & 2 PI-SW-145 could be performed using only indirect reflected lighting produced by the existing battery-powered emergency lighting units. The inspectors considered this test acceptable to demonstrate that the available emergency battery lighting in the service water building was adequate to allow the operators to perform the required shutdown actions denoted in the ASSD procedure.

c.

Conclusions The maintenance inspection and surveillance test program for the emergency 8-hour battery-powered lighting system was sufficient to ensure that the system design function was met. The emergency lighting units were operational and the lighting heads were aimed to provide adequate illumination to perform the required shutdown actions denoted in ASSD procedures.

F3.3 Review of 10 CFR 50, Appendix R, ASSD Emergency Communications

a.

Inspection Scope (64704)

The inspectors reviewed the periodic testing of the ASSD sound-powered phone system and inventory surveillance of ASSD operator equipment, and inspected the sound-powered phone jacks identified in the ASSD procedures.

b.

Observations and Findings The inspectors reviewed procedure 0PT-48.4, ASSD Sound Powered Phone System Functional Test," Rev. 9, which was last performed on September 6. The inspectors determined that the scope and content of the periodic test procedure was sufficient to verify the functional operation of the sound-powered phone system. The procedure was comprehensive and detailed. It verified the proper inventory and physical condition of the phone head-sets, connectors, and cables; and the replacement of the amplifier unit batteries. It also verified that voice communications between all phone jack locations were audible and discernible.

The inspectors walked down the remote shutdown equipment identified in procedure ASSD-02 in the Unit 2 reactor building, diesel building, and service water building and verified that the ASSD sound-powered phone jacks were at the locations identified in Sections E, F, & G of ASSD-02. The inspectors observations of the material condition of selected sound-powered phone stations found that the ASSD sound-powered phone jacks were in good condition and free of foreign material.

c.

Conclusions The surveillance test program for the ASSD sound-powered phone system was sufficient to verify proper operation of the system. The sound-powered phone jacks were installed at the proper locations to support required shutdown actions identified in the ASSD procedures.

F4 Fire Protection Staff Knowledge and Performance F4.1 Loss of Plant Fire Suppression

a.

Inspection Scope (71750, 71707)

The inspectors reviewed the circumstances surrounding the licensees discovery that the engine-driven fire pump (EDFP) had been inoperable for approximately 16 days as a result of a damaged temperature switch.

b.

Observations and Findings On August 23, 1999, during routine review of operator logs, the inspectors noted an entry regarding the unsatisfactory performance of Periodic Test 0PT-34.1.1.0, Fire Pump Test (Motor-Driven and Engine Driven), Rev. 14. During the August 22, performance of the test, the EDFP had been stopped by the operators as a result of antifreeze spraying from the pump engine cooling water casing. CR 99-2093, Diesel Fire Pump, was generated to document this condition and a review of past pump operability was performed by the licensee. This review revealed that the breach was caused by a damaged EDFP engine temperature switch. The temperature switch had been damaged on August 9, when a clearance was being hung to support maintenance on a relief valve for the motor-driven fire pump (MDFP). While gagging an EDFP relief valve, a maintenance worker had dropped a wrench, knocking the temperature switch off the EDFP. CR 99-1989, Diesel Fire Pump Inoperability, was initiated at that time.

Initial investigations erroneously determined that the loss of the temperature switch would not affect EDFP operability. The review had focused on the temperature function of the switch and not the coolant system integrity function. Consequently, the licensee had proceeded to remove the redundant MDFP from service to perform relief valve maintenance. It was inoperable for a total of 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> and 20 minutes.

On September 1, the licensee determined that the EDFP had been inoperable since the August 9 event, based on the breach in the cooling system. In addition, the licensee determined that the subsequent removal of the MDFP from service rendered the water fire suppression system inoperable for a total of approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. The licensee also determined that having both fire pumps unavailable constituted a condition outside of the fire protection design bases. The licensee subsequently made a report to the NRC under 10 CFR 50.73 in regard to this condition (see LER 50-325(324)/1999-008-00).

The inspectors reviewed the Fire Hazard Analysis and the licensees safe shutdown analysis. In discussions with the licensee, the inspectors noted that there were no portable pumps onsite of large enough capacity to support the flow requirements in the event of a fire. In addition, the licensee indicated that there was no procedural guidance for the establishment of backup water fire suppression. The inspectors concluded that the licensees ability to mitigate a fire was severely degraded during this time due to unavailability of other means to provide backup water suppression. Pending further NRC staff review of the licensees risk analysis, as well as the potential consequences of a fire during the concurrent pump inoperability, this issue is identified as URI 50-325(324)/99-07-02, Fire Pump Concurrent Inoperability.

c.

Conclusion Licensee personnel failed to correctly identify that a missing temperature switch affected the operability of the EDFP and to correct this condition. As a result of this failure, licensee personnel subsequently allowed the MDFP to be removed from service for maintenance. With both pumps concurrently inoperable for approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />, the licensees ability to mitigate a fire was severely degraded due to the unavailability of other means to provide water fire suppression. This condition put the plant outside of the fire protection design basis. A URI was initiated to further review the licensees risk analysis and to determine the potential consequences of a fire should one have occurred during the concurrent pump inoperability.

F7 Quality Assurance in Fire Protection Activities F7.1 Review of the Status of the Fire Protection Program Upgrade (FPPU) Project

a.

Inspection Scope (64704)

The inspectors observed a weekly meeting associated with the FPPU project status and reviewed the FPPU Part 2 work-off schedule for the status of the corrective actions being implemented for previously-identified Nuclear Assessment Section (NAS) Audit Report findings.

b.

Observations and Findings The inspectors observed the licensees weekly status meeting conducted on September 28, which was associated with the review of the FPPU schedule for corrective actions for NAS findings. The status meeting had representation that included operations, maintenance, engineering, work control, fire protection, NAS, and regulatory affairs. The FPPU project task leaders reviewed the status of task actions for the FPPU Part 2 work-off schedule and for 24 open audit findings identified in NAS Audit Reports B-FP-97-01, B-FP-98-01, and B-FP-99-01. The inspectors noted that coordination between staff organization representatives for operations, fire protection, and engineering was effective at the weekly meeting. A self-assessment to evaluate the overall effectiveness of the FPPU project implementation was in progress.

c.

Conclusions The fire protection upgrade project meeting discussions on the status task actions for the FPPU Part 2 work-off schedule were well-coordinated and productive. Completion of corrective actions associated with the upgrade project continued to be progressing on schedule. Management attention to the site fire protection program was effective in ensuring proper prioritization of work assignments and scheduling of FPPU project action items.

F8 Miscellaneous Fire Protections Issues (92904)

F8.1 (Closed) URI 50-325(324)/99-02-05: Fire Barrier Penetration Seal Inspection. This URI involved the potential of one side of fire barrier penetration seals to degrade when only the other side of the seals had been inspected. This condition affected penetration seals in both reactor buildings; the control, service water, and diesel generator buildings; the EDG 4-day tank room; and the augmented off-gas building. Fire impairments were initiated for the penetration seals in all of these buildings.

The inspectors reviewed the associated CR 99-00619, a summary of the inspection results for fire barrier inspections completed in August 1999, training requirements and qualifications of the penetration seal inspectors, and other related documentation.

Based on their review of the licensees fire barrier inspection summary, the inspectors concluded that no significant findings were identified during the licensees inspection effort. There were no through-barrier openings or gaps identified in the inspections that would have degraded the effectiveness of the fire barrier features to perform their

intended function; plant safe shutdown capability was adequately protected as required by 10 CFR 50, Appendix R, Section III.G.

V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on November 1, 1999. The licensee acknowledged the findings presented. No proprietary information was identified.

PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Security Manager N. Gannon, Plant General Manager J. Gawron, Nuclear Assessment Manager S. Hardy, Fire Protection Engineer M. Herrell, Training Manager K. Jury, Regulatory Affairs Manager J. Keenan, Site Vice President J. Lyash, Director of Site Operations G. Miller, Brunswick Engineering Support Section Manager W. Noll, Operations Manager E. Quidley, Maintenance Manager S. Rogers, Outage and Scheduling Manager INSPECTION PROCEDURES USED IP 37551:

Onsite Engineering IP 61726:

Surveillance Observations IP 62706:

Maintenance Rule IP 62707:

Maintenance Observation IP 64704:

Fire Protection Program IP 71707:

Plant Operations IP 71750:

Plant Support Activities IP 90712:

In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92904:

Followup - Plant Support IP 93702:

Prompt Onsite Response to Events at Operating Power Reactors

ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-324/99-07-01 NCV Startup Procedure Noncompliances (Section O1.1) 50-325(324)/99-07-02 URI Fire Pump Concurrent Inoperability (Section F4.1)

Closed 50-324/99-07-01 NCV Startup Procedure Noncompliances (Section O1.1) 50-324/1998-004-00 LER High Pressure Coolant Injection System Rendered Inoperable (Section O8.1) 50-325(324)/1999-008-00 LER Electric Motor Driven and Diesel Driven Fire Pump Concurrent Inoperability (Section O8.2) 50-325(324)/99-07-02 NCV Failure to Restore Fire Pump (Section F4.1) 50-325(324)/99-02-05 URI Fire Barrier Penetration Seal Inspection (Section F8.1)

Discussed 50-325(324)/98-08-02 IFI Review Licensee Actions to Resolve DC Ground Problems (Section P1.1)