ML993540151

IRC Brunswick 1999004 Integrated

ML993540151
Person / Time
Issue date:	07/19/1999
From:	Division Reactor Projects II
To:
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Download: ML993540151 (30)

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July 19, 1999 EA 99-173 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. 50-325/99-04 AND 50-324/99-04

Dear Mr. Keenan:

This refers to the inspection conducted on May 9 through June 19, 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 three violations of NRC requirements occurred. These violations are being treated as Non-Cited Violations (NCVs),

consistent with Appendix C of the Enforcement Policy. These NCVs are described in the subject inspection report. If you contest the violations or severity level of these NCVs, 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.

In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter and its enclosure 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 2

Enclosure:

Integrated NRC Inspection Report cc w/encl:

Director Site Operations Brunswick Steam Electric Plant Carolina Power & Light Company P. O. Box 10429 Southport, NC 28461 J. J. Lyash, Plant Manager Brunswick Steam Electric Plant Carolina Power & Light Company P. O. Box 10429 Southport, NC 28461 Terry C. Morton, Manager Performance Evaluation and Regulatory Affairs CPB 9 Carolina Power & Light Company P. O. Box 1551 Raleigh, NC 27602-1551 K. R. Jury, Manager Regulatory Affairs Carolina Power & Light Company Brunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461-0429 William D. Johnson Vice President & Corporate Secretary Carolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602 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 3825 Barrett Drive Raleigh, NC 27609-7721 Karen E. Long Assistant Attorney General State of North Carolina P. O. Box 629 Raleigh, NC 27602 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 Jerry W. Jones, 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 William H. Crowe, Mayor City of Southport 201 E. Moore Street Southport, NC 28461 Distribution w/encl: (See page 3)

CP&L 3

Distribution w/encl:

L. Plisco, RII B. Bonser, RII J. Lieberman, OE A. Hansen, NRR G. MacDonald, RII G. West, RII PUBLIC NRC Resident Inspector U. S. Nuclear Regulatory Commission 8470 River Road, SE Southport, NC 28461

• FOR PREVIOUS CONCURRENCE - SEE ATTACHED COPY OFFICE DRP/RII DRP/RII DRP/RII DRP/RII DRP/RII DRP/RII DRS/RII SIGNATURE NAME

• WWest:vg

• TEaslick

• EBrown

• EGuthrie

• FJape

• BHolbrook

• FWright DATE 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE EICS/RII SIGNATURE NAME SSparks DATE 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICIAL RECORD COPY DOCUMENT NAME: G:\\BRU\\REPORT\\9904.drp

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

50-325, 50-324 License Nos:

DPR-71, DPR-62 Report No:

50-325/99-04, 50-324/99-04 Licensee:

Carolina Power & Light (CP&L)

Facility:

Brunswick Steam Electric Plant, Units 1 & 2 Location:

8470 River Road SE Southport, NC 28461 Dates:

May 9 - June 19, 1999 Inspectors:

E. Brown, Resident Inspector E. Guthrie, Resident Inspector T. Easlick, Senior Resident Inspector B. Holbrook, Project Engineer (Sections O1.1, O2.5, O4.3, O4.4, O5, O7.2)

F. Wright, Senior Radiation Specialist (Sections R1.1, R1.2)

F. Jape, Senior Project Manager (Section E8.2)

Approved by:

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

EXECUTIVE

SUMMARY

Brunswick Steam Electric Plant, Units 1 & 2 NRC Inspection Report 50-325/99-04, 50-324/99-04 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 sustained control room and plant observation, and radiological protection inspections, as well as a year 2000 readiness program review by regional inspectors.

Operations Operations personnel generally demonstrated strong command and control of control room activities during normal operations on Unit 1 and startup activities on Unit 2.

Procedural requirements for command, control, and communications were met. Senior site management, as well as department and first line supervisors, demonstrated strong supervisory oversight of observed activities (Section O1.1).

A pre-startup inspection of the drywell found that general housekeeping was adequate to ensure the drywell was free of foreign material and ready to support a plant startup.

Health physics support and coordination for this activity were effective in reducing personnel exposure (Section O2.1).

Configuration control of safety-related equipment was correctly maintained. Technical Specification-required surveillance tests and instrument checks were correctly performed and accurately recorded. Procedural and regulatory requirements were met for inoperable equipment and Limiting Conditions for Operation were correctly identified and recorded (Section O2.5).

Operating experience was not comprehensively communicated during a pre-job briefing for transitioning from dual-loop reactor recirculation pump operation to single loop operation, and proposed contingencies for monitoring alternate bottom-head drain temperature monitoring were inadequate (Section O4.2).

Fire watch requirements were being met for the areas with deficient fire protection equipment. However, some administrative aspects of the fire watch program were not being performed. These administrative deficiencies did not have a significant safety impact on plant operations. However, they did demonstrate a lack of detailed operations oversight of the fire watch program (Section O4.3).

Operators generally followed good operating practices and maintained shift professionalism in conducting plant operations. Operators were aware of ongoing plant activities and surveillance testing. Administrative controls were adequate to ensure in-plant work activities were being performed with the knowledge of control room personnel. However, a violation was identified when an operator failed to follow

6 procedure during the alignment of the condensate system pumps. This resulted in the inadvertent start of two condensate pumps and one condensate booster pump (Section O4.4).

Licensed operator candidates performing on-the-job training in the control room were closely monitored by licensed operators assigned oversight responsibility. This was considered to be a strength (Section O5).

A violation was identified for the failure of the licensee to initiate condition reports for trips of the reactor protection system and the manipulation of a component in the control room without proper authorization. A negative trend in the identification of nonconforming conditions was identified based on these findings, as well as licensee and third-party assessments (Section O7.1).

A violation was identified for the licensee determination that the B low pressure coolant injection subsystem had been inoperable for greater than the Technical Specification allowed action time. The subsystem inoperability was a result of missing valve actuator components in the reactor recirculation (RCR) system discharge bypass valve which caused valve binding on three occasions. The valve binding prevented the valve from closing and therefore made the valve inoperable (Section O8.1).

Maintenance Maintenance activities observed were performed consistent with the applicable procedures, which were verified to be of the proper revision and implemented using the correct level-of-use. Three-part communications were observed. Test equipment was verified to be within the current calibration cycle (Section M1.1).

The licensee identified that a single fuel rod had multiple cracks totaling approximately 120 inches long. Early identification and effective suppression resulted in cracks that were narrow. A discernable fret mark was noted, although no debris was located at the site of the fretting. The failed fuel inspection activities were well planned with ample health physics support including an emphasis on exposure reduction during the work (Section M2.1).

Control of foreign material in foreign material exclusion areas remained a challenge during the Unit 2 refueling outage. Eight foreign material items were found to be in the reactor vessel and the fuel pool during the Unit 2 refueling outage. Corrective actions implemented by the licensee for foreign materials in the reactor vessel and the fuel pool were effective in minimizing the risk to fuel integrity (Section M2.2).

Engineering During the Unit 2 refueling outage, the licensee did not adequately address or disposition an identified problem with vendor contractor work at the facility. One issue involved incorrect configuration of MOV wire jumpers, and the other concerned a wedge spring and spring retainer plate which were not installed in an RCR valve in accordance

7 with plant drawings. However, the licensee had recently changed its control of vendor contractor work to require that individuals be qualified in Brunswicks quality assurance program, that the vendor use Brunswick facility procedures, and that a Brunswick project manager be assigned to each work task. The licensee stated that in the past, vendor work activities were not always monitored such that quality standards were achieved (Section E2.1).

The plant Y2K Readiness Project activities and contingency planning were about 99 percent complete. The digital feedwater modification for Unit 2 has been completed, and was scheduled to be installed for Unit 1 by November 16, 1999. All other Y2K activities were scheduled to be completed by the end of June 1999 (Section E8.2).

Plant Support Health physics support of operations and maintenance activities was good. Adequate coverage was noted during observed maintenance activities. The use of individual radio headsets and remote-indicating dosimetry allowed personnel in the drywell to reduce the time spent in high dose rate areas and thereby reduce personnel exposure (Section R1.1).

Licensee radiation surveys, postings, access controls, and radiological work controls were effective and were performed in accordance with regulatory requirements. About half of the ten radiation workers questioned concerning knowledge of their dosimetry alarm setpoints did not know their alarm setpoints (Section R1.2).

Individual radiation doses were well below regulatory limits. The Brunswick ALARA program reduced site collective personnel radiation doses for planned activities (Section R1.3).

Report Details Summary of Plant Status Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On May 23 power was reduced to 49 percent RTP as a result of the runback of both reactor recirculation pumps. The recirculation pump runback was a result of the failure of the B reactor feedwater pump motor gear unit (MGU). The MGU was repaired and power was returned to 100 percent RTP on May 25. At the end of the report period the unit had been operating continuously for 145 days.

Unit 2 began the report period in cold shutdown for scheduled refueling activities. The unit was returned to 100 percent RTP on May 23 at 3:32 p.m. The refueling outage lasted for 36 days and 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. At the end of the report period the unit had been operating continuously for 27 days.

I. Operations O1 Conduct of Operations O1.1 Oversight, Command and Control, and Communications During Control Room Activities

a.

Inspection Scope (71715)

The inspectors observed operator performance during normal operations on Unit 1 and activities in preparation for a Unit 2 startup following a scheduled refueling outage.

Observations were compared to procedural and regulatory requirements. The inspectors reviewed procedures and assessed supervisory oversight, command and control, and communications during control room activities. Among the procedures reviewed were the following:

0OI-01.00, Conduct of Operations Manual Overview, Revision (Rev.) 1 0OI-01.01, Operations Unit Organization and Administration, Rev. 9 0OI-01.02, Shift Routines and Operating Practices, Rev. 14 0OI-01.03, Control Room Activities, Rev. 6 0OI-01.04, Communications, Rev. 9 0AP-50, Site, Command, Control, and Communications, Rev. 0

b.

Observations and Findings The inspectors observed generally strong command and control of control room activities. The startup activities following a scheduled refueling outage on Unit 2 were controlled by the Senior Control Operator (SCO) and Senior Reactor Operators (SROs) responsible for the command and control functions of the control room. The operators effectively controlled routine control room activities as well as startup surveillance

9 activities. Additionally, maintenance, instrumentation and control, and engineering support activities during troubleshooting, repair, and testing were the subject of close attention to detail and oversight. The inspectors observed that, at one time during the startup preparations, four major activities were taking place simultaneously. However, the inspectors noted that extra personnel were assigned to the shift and generally performed their assigned tasks without error. There was one example where operator switch manipulation resulted in an unexpected automatic start of Unit 2 Condensate system pumps. This issue is discussed in Section O4.4 of this inspection report. The inspectors noted that the number of activities occurring simultaneously in the control room challenged operator communications and response to control room alarms. On occasion, the inspectors noted a slight difference in individual communication techniques for control room alarm announcements and three-part communication repeat backs. In every case, the inspectors observed that the operators, SCO or SRO made on-the-spot corrections to maintain the communication standard.

The inspectors observed that the control room activities were almost always monitored and observed by a member of site management. The Plant General Manager was in the control room on a daily basis to discuss plant and equipment status. The Operations Manager or his designee was also observed in the control room frequently and participated in briefings and routine meetings.

c.

Conclusions Operations personnel generally demonstrated strong command and control of control room activities during normal operations on Unit 1 and startup activities on Unit 2.

Procedural requirements for command, control, and communications were met. Senior site management, as well as department and first line supervisors, demonstrated strong supervisory oversight of observed activities.

O2 Operational Status of Facilities and Equipment O2.1 Drywell Closeout Inspection

a.

Inspection Scope (71707)

On May 18, the inspectors accompanied the plant manager on an inspection of the Unit 2 drywell in preparation for closeout of the drywell.

b.

Observations and Findings The inspectors toured all elevations of the drywell to verify that the material condition of the drywell supported plant startup. During this outage a number of maintenance activities focused on the recirculation system in the area of the five foot (ft) elevation.

These areas were found to be free of foreign material with the exception of several small pieces of debris including plastic tiewraps and metal labels. These items were later removed from the drywell. The inspectors observed drywell liner repairs in several locations which were completed during the outage. Additionally, the inspectors

10 observed a weld repair that was completed on a jet pump instrument line. No deficiencies were noted. General area housekeeping was good and the drywell was free of foreign materials.

Health physics support for this activity was excellent. A detailed pre-evolution briefing was conducted that included safety, foreign material exclusion area, and radiological information. The use of individual radio headsets and remote indicating dosimetry facilitated good coordination with the technicians outside the drywell monitoring the inspection activities. This coordination allowed personnel in the drywell to reduce the time spent in high dose areas and thereby reduce personnel exposure.

c.

Conclusions A pre-startup inspection of the drywell found that general housekeeping was adequate to ensure the drywell was free of foreign material and ready to support a plant startup.

Health physics support and coordination for this activity were effective in reducing personnel exposure.

O2.2 Standby Liquid Control (SLC) System Walkdown (71707)

The inspectors performed a walkdown of the Unit 1 and 2 SLC systems on June 8.

Accessible valves, electrical breakers, and reactor turbine gauge board (RTGB) controls were verified to be in the proper alignment in accordance with Operating Procedure 1(2)

OP-05, Standby Liquid Control System, Revs. 32 and 47, respectively. The inspectors verified that SLC tank concentration, level, and temperature were within the limits of the applicable Technical Specification (TS). The areas around the SLC components were free of transient combustible material and access to the motor control centers (MCCs) was not inhibited by staged equipment.

O2.3 Torus Inspection (71707, 62707)

On May 12 the inspectors performed a visual inspection of the Unit 2 torus. The inspectors reviewed the suppression pool volume for evidence of material that could clog the emergency core cooling systems suction strainers. The suppression pool water was found to be relatively clear and free of foreign material. No evidence of paint or coating degradation was noted. The inspectors examined the internals of all drywell-to-torus vacuum breakers to ensure no foreign material was present. Concurrently, the inspectors observed a portion of Periodic Test 0PT-80.1, Reactor Pressure Vessel ASME Section XI Pressure Test, Rev. 39. Technicians performed a thorough examination of the procedurally designated torus connections. One minor discrepancy was identified by the technicians and appropriately corrected.

O2.4 Standby Liquid Control Clearances (71707)

On May 12 the inspectors walked down clearances 2-99-0004 and 2-99-0004A. These clearances were hung to support maintenance on several valves and various surveillance tests. Accessible valves were verified by the inspectors to be in their

11 designated positions. Electrical feeder breakers were verified to be racked out or locked off as appropriate. Clearance tags reviewed were properly marked and hung.

The inspectors verified that clearance actions were maintained consistent with the applicable TS section.

O2.5 System Alignment and Configuration Control

a.

Inspection Scope (71715)

The inspectors observed operator performance during normal operations on Unit 1 and activities in preparation for a Unit 2 startup following a scheduled refueling outage.

Observations were compared to procedural and regulatory requirements. Among the procedures reviewed were the following:

0GP-01, Prestartup Checklist, Rev. 147 0GP-02, Approach to Criticality and Pressurization of the Reactor, Rev. 65 0OI-01.08, Control of Equipment and System Status, Rev. 22 0OI-03.3, Auxiliary Operator Daily Surveillance Report, Rev. 40 2OI-03.2, Control Operator Daily Surveillance Report, Rev. 65 0OI-01.09, Equipment Tagging, Rev. 2

b.

Observations and Findings The inspectors observed that control room operators correctly maintained configuration control of safety-related systems in preparation for the Unit 2 startup. System status and alignment were routinely verified by Reactor Operators (ROs) and SRO supervisors in the control room. Surveillance checks required by the TS were completed at the required frequency and were accurately recorded. The inspectors noted that one step in the procedure used by the Auxiliary Operator to record the TS required emergency diesel generator (EDG) fuel oil level was not consistent with other procedure steps. The procedure step failed to reference the applicable TS requirement. This observation was discussed with operations management.

The operating condition of plant equipment was effectively monitored and appropriate corrective actions were initiated when required. Limiting Condition for Operations (LCOs) and tracking LCOs were correctly identified and recorded.

The inspectors observed that during a panel walkdown and equipment clearance verification, an SRO identified administrative deficiencies associated with an equipment clearance on the Unit 2 Gland Seal System for a Reactor Feedwater pump. Three clearance information tags had been removed but were not signed off as being removed.

Also, a valve cover was still in place that should have been removed when the clearance was canceled. The licensee documented this deficiency in Condition Report (CR) 99-01350 to ensure corrective actions were completed. The inspectors concluded that this licensee identified administrative oversight did not affect plant safety.

12 The inspectors noted that the licensee had developed a flow chart type of operator aid that identified the major milestones of the general operating procedures. The operators and management personnel effectively used the flow chart for overview and planning purposes to ensure system configuration and availability were addressed in a timely manner.

The inspectors reviewed the control process for disabled annunciators and noted that all disabled annunciators were properly identified and documented. The inspectors also noted that the high bearing temperature annunciator for EDG 4 had been disabled on September 15, 1998. A discussion with the field SRO, who routinely provided oversight of Auxiliary Operators (AO), and two AOs revealed that they were not aware that the alarm had been disabled. The licensee did not regard the disabled alarm as a problem since an AO was required to monitor the bearing temperatures locally when the EDG was in operation. The licensee had not assessed the consequences if the AO was required to leave the area to perform other duties during transient or emergency conditions. Operations supervision stated they would review the issue to determine if other compensatory measures would be required.

The inspectors observed that, except for a recurring direct current (DC) ground, the Unit 1 control room maintained a black board concept with no annunciators in alarm. The inspectors were informed that the DC ground alarm had been actuating occasionally for about a month. Operations personnel were attempting to locate the ground in accordance with applicable procedures.

The inspectors reviewed the site Probabilistic Safety Assessment (PSA) for dominant operator actions that contribute to increased system failure or higher core damage frequency. The operator actions evaluated in the PSA were based on proceduralized steps. The inspectors randomly selected operator actions and verified the procedures clearly defined operator actions and that they were adequate for the circumstance. No deficiencies were identified.

c.

Conclusions Configuration control of safety-related equipment was correctly maintained. TS required surveillance tests and instrument checks were correctly performed and accurately recorded. Procedural and regulatory requirements were met for inoperable equipment and LCOs were correctly identified and recorded.

O4 Operator Knowledge and Performance O4.1 Unit 1 Reactor Building Auxiliary Operator (RBAO) Daily Rounds (71707)

On June 11 the inspectors observed the Unit 1 RBAO during the performance of Operating Instruction 1OI-3.4.2, Unit 1 Reactor Building Auxiliary Operator Daily Check Sheets, Rev. 15. The inspectors observed that the procedure was in use and of the proper revision. The inspectors observed that the RBAO verified reactor building equipment was operating within expected parameters and conditions specified by the

13 procedure. The inspectors observed that the RBAO was knowledgeable of plant conditions as well as work in progress, and that a thorough building walkdown was conducted.

O4.2 Unit 2 Single-Loop Operation

a.

Inspection Scope (71707)

The inspectors observed operations startup activities, from a refueling outage on Unit 2, during the transitioning from dual-loop reactor recirculation (RCR) pump operation to single-loop. Single-loop operation was necessary to perform maintenance activities on the A RCR motor-generator (MG) set tachometer.

b.

Observations and Findings On May 21 with Unit 2 at one percent RTP and reactor coolant system pressure around 100 pounds per square inch gauge (psig) the inspectors attended a pre-job briefing for going into single RCR loop operation. The inspectors observed that, during discussion of contingencies, review of the relevant abnormal operating procedure (AOP) had been conducted only for dual-loop operation and not single-loop. The inspectors noted that the operators did not reference the site lessons learned database even though on January 23, 1999, Unit 1 inserted a manual scram due, in part, to several issues concerning operator knowledge.

The inspectors were concerned over proposed contingency actions to be taken in the event of erratic readings from the bottom-head drain temperature indicator, which had produced erratic readings previously. During the briefing, the shift supervisor discussed the use of alternate temperature indicators. The inspectors noted that the alternate indicators suggested (reactor vessel metal temperature and recirculation pump suction temperatures) would not have provided an accurate indication of actual bottom-head temperature. This observation was based on a review of the temperature data from the January 1999 stratification event. The inspectors discussed these concerns with the licensee. After review of the system prints and further discussion, the shift supervisor (SS) determined and communicated to the plant operators that there were no real-time redundant temperature indications should erratic readings be seen on the bottom-head drain temperature indicator. The inspectors observed that during the tachometer repair, contingencies were not necessary due to the maintenance of adequate forced circulation.

c.

Conclusions Operating experience was not comprehensively communicated during a pre-job briefing for transitioning from dual-loop reactor recirculation pump operation to single loop operation, and proposed contingencies for monitoring alternate bottom-head drain temperature monitoring were inadequate.

14 O4.3 Fire Watch Program

a.

Inspection Scope (71715)

The inspectors reviewed procedure 0FPP-005, Fire Watch Program, Rev. 16, and assessed operations performance with respect to procedure requirements.

b.

Observations and Findings The inspectors observed that the procedure described personnel responsibilities and the process to ensure fire watches were correctly established. The inspectors verified that fire watch requirements were being met for the areas with deficient fire protection equipment. However, the inspectors identified that some administrative aspects of the procedure were not being performed. For instance, the SCO or his designee was identified as having the responsibility to periodically check the outstanding fire watch assignments to verify compliance with the applicable compensatory measures.

Additionally, completed fire watch logs were to be reviewed and retained for 90 days.

The inspectors did not find evidence that these actions were being performed. Though no violation of regulatory requirements was identified, these deficiencies demonstrated a lack of detailed operations oversight of the fire watch program. The licensee documented these deficiencies as CR BNP 99-01365 to ensure corrective actions would be completed.

c.

Conclusions Fire watch requirements were being met for the areas with deficient fire protection equipment. However, some administrative aspects of the fire watch program were not being performed. These administrative deficiencies did not have a significant safety impact on plant operations. However, they did demonstrate a lack of detailed operations oversight of the fire watch program.

O4.4 Operator Performance

a.

Inspection Scope (71715)

The inspectors reviewed applicable procedures and assessed operations implementation of the procedure requirements. Among the procedures reviewed were the following:

0OI-01.10, Independent Verification, Rev. 1 0OI-01.11, Logkeeping, Rev. 6 0OI-01.12, Shift Turnover, Rev. 11 0OI-01.14, Shift Orders, Rev. 7 0OI-01.15, Operations Procedures,Rev. 4

15

b.

Observations and Findings The inspectors observed that operators were attentive and responsive to plant parameters and conditions. Operators were aware of the reasons for annunciators that were in alarm. Logkeeping was generally timely and accurate. Plant evolutions and testing were planned and properly authorized. Abnormal conditions and equipment problems were evaluated promptly to determine the impact on plant safety and equipment operability. Shift turnovers were professional and provided the oncoming shift with an adequate update from the last time they were on shift. Operators demonstrated good diagnostic skills associated with a Unit 2 Residual Heat Removal valve leak-by problem simultaneously with increased suppression pool level. Operators correctly determined which valve was leaking-by.

The inspectors observed an example of operator procedure usage that was inconsistent with site procedures. During control rod movement activities, the SRO directed the RO to take actions from a section of the procedure that was not being implemented at the time. The inspectors were informed that the procedure in use was a combination of two previous procedures and the current revision was not as clear as it should have been.

The inspectors verified that the procedure revision process was initiated the next day instead of the day the procedure problem was identified. The inspectors verified that the operator actions taken were satisfactory with respect to system and equipment operation. This observation was discussed with site management personnel for resolution.

On May 19, the licensee identified that switch manipulations had resulted in the inadvertent automatic start of the Unit 2 2B and 2C condensate pumps and the 2B condensate booster pump. The previous day, operators had completed the restoration of a Startup Auxiliary Transformer (SAT) and realigned electrical loads from a backfeed condition. The SAT restoration procedure required the control switches for the condensate system pumps to be placed in manual. During the pre-job briefing for the SAT restoration, the day shift operators identified that the procedure did not include steps for condensate system restoration, i.e., placing the pump control switches back in automatic. The operators discussed this problem and decided that the condensate pump control switches could be realigned (placed back in automatic) following the SAT restoration and that a Procedure Action Request (PAR) would be submitted later to include the required procedure steps. However, after the SAT restoration, the switches were inadvertently not placed back in automatic. This information was not communicated to the oncoming night shift during shift turnover and the shift turnover board walkdown failed to identify the switches as out-of-position.

Licensee management informed the inspectors that the off-going operator later remembered that the pump switches had not been placed back in automatic, but decided that restoration could wait until he returned to work the following day. During the shift turnover board walkdown the next morning, the oncoming and offgoing operators discussed the switch positions. Because of poor communications, the oncoming shift operator believed he had permission and repositioned the switches to automatic. The condensate system pumps automatically started on low pressure. The

16 operator who manipulated the switches had not officially assumed the watch and was not consulting the required procedure. The onshift SRO was informed of the transient.

He directed the operators to place the switches back in manual and to secure the pumps. The onshift SRO informed the oncoming SRO of the problem. No operator log entry was made following the transient and no condition report was generated. After the oncoming shift assumed duties, the RO and SRO discussed the transient with the Shift Superintendent (SS). The SS did not complete a review of the problem, inform management, make a log entry, or inform the oncoming night shift SS at the end of his watch. Later, the night shift SS learned of the problem and informed operations management. Operations management initiated a review of the transient and CR 99-01342 was completed.

The inspectors reviewed the evaluation and circumstances surrounding the transient.

The inspectors observed that the Condensate and Feedwater procedure, 2OP-32, which should have been used to manipulate the condensate system pump control switches, was identified as a continuous use procedure. Procedure 0AP-010, Procedure Use and Adherence, Rev. 6, step 5.2.3 required, in part, that the procedure or applicable parts shall be available at the location of the work activity and each step of the procedure shall be read directly by the user or designated reader before performing the steps of the procedure. Contrary to the above requirements, an operator manipulated the condensate system pump control switches without the procedure being read directly by the user or a designated reader. As a result, a system transient occurred due to the automatic start of the condensate and condensate booster pumps. The inspectors determined that the failure to follow procedure OAP-010 while manipulating the condensate system constituted a violation of Technical Specifications 5.4.1.a for procedure usage. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV) consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensees corrective action program as CR 99-01342. This violation is identified as NCV 50-324/99-04-01, Failure to Follow Procedure Results in Condensate System Transient.

The inspectors discussed the violation, operator performance, and the failure of multiple barriers that contributed to the violation with licensee management. Specific operator performance issues discussed included the following: operator good practices such as peer checks and self verification were not performed, pre-job briefing guidance for system restoration was not followed, operator and supervisor log entries for a system transient were not made, a condition report was not generated, operations management was not immediately informed of the transient, an operator who was not officially on shift performed control board manipulations without permission, control room communications were unclear, and control room supervisors did not provide oversight or pursue the cause of the system transient.

c.

Conclusions Operators generally followed good operating practices and maintained shift professionalism in conducting plant operations. Operators were aware of ongoing plant activities and surveillance testing. Administrative controls were adequate to ensure in-

17 plant work activities were being performed with the knowledge of control room personnel. However, a violation was identified when an operator failed to follow procedure during the alignment of the condensate system pumps. This resulted in the inadvertent start of two condensate pumps and one condensate booster pump.

O5 Licensed Operator Requalification Program Evaluation (71001)

The inspectors observed that licensed operator candidates performing on-the-job-training in the control room were closely monitored by licensed operators assigned oversight responsibility. Coaching for procedure usage, communications, control room protocol, and safety-related equipment testing methodology was prompt, clear, and concise. Peer checks and independent verifications were continuous. The oversight of on-the-job-training of licensed operator candidates was a strength.

O7 Quality Assurance in Operations O7.1 Identification of Nonconforming Conditions

a.

Inspection Scope (71707)

The inspectors reviewed several known nonconforming or adverse conditions to determine whether these conditions were properly included in the licensees corrective action program (CAP).

b.

Observations and Findings During the Unit 2 refueling outage, problems with spiking on several local power range monitors (LPRMs) and intermediate range monitors (IRMs) resulted in three reactor protection system (RPS) trips. Two of the trips occurred on April 30, 1999, and the third on May 15. The inspectors reviewed Nuclear Generation Group Standard Procedure CAP-NGGC-0001, Corrective Action Management, Rev. 4. Section 3.0, which defined an adverse condition as a deficiency, failure, malfunction, deviation, abnormal occurrence, defective material or equipment, or nonconformance in an item or activity which has affected or reasonably could affect nuclear or personnel safety, quality, or compliance with regulations. The inspectors determined that repeated unscheduled actuations of the RPS constituted an adverse condition. Several days later, during the inspectors follow-up of the resolution of these events, the inspectors noted that no CR had been generated for the trips. The inspectors notified the licensee and subsequently CRs 99-1149, U2 RPS Trip/No Rod Motion, and 99-1315, Unit 2 RPS trip (IRM H), were initiated.

Also during this inspection period, as described in Section O4.4, the licensee identified that a CR was not initiated when the oncoming Unit 2 control operator (CO) manipulated reactor turbine gage board (RTGB) controls without permission from the CO of the watch, or procedural guidance. The switch manipulations resulted in the auto-start of two condensate pumps and one condensate booster pump on low header pressure.

The inspectors noted that a CR was not written until the next day, in spite of the fact that

18 operators stated that the event was significant. The inspectors had previously noted a similar deficiency with the resolution of an operability question for a safety-related pressure instrument, as described in Section O2.1 of NRC Inspection Report 50-325(324)/99-03.

The inspectors reviewed past licensee and third-party assessments for 1998. The Nuclear Assessment Section (NAS) assessment B-OP-98-01, dated December 2, 1998, contained Issue B-OP-98-01-I2 which stated that, [s]ome aspects of the operations self evaluation program are not adequately managed to ensure program and plant deficiencies are adequately identified and tracked. This issue included some licensee examples. The proposed actions to address these issues consisted of various levels of counseling and benchmarking. The inspectors reviewed the associated CR action items and observed that the corrective actions for this issue had been completed in February 1999. The associated effectiveness review indicated Operations CAP compliance and its timely completion of corrective actions. However, based on these examples, the inspectors concluded that a negative trend continued for the timely initiation of CRs in Operations. Additionally a third-party review identified that the threshold for CR initiation varied throughout the site. Individuals were noted to focus on the resultant workload from the CR prior to writing it rather than the benefits of self-identifying problems.

10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measure shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action shall be documented and reported to appropriate levels of management. The failure of the licensee to initiate CRs for trips of the RPS on April 30 and May 15 until mentioned by the inspector, and the failure to initiate a CR for the manipulation of RTGB components without proper authorization constitute a violation. This Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy.

This violation is in the licensees CAP as CR 99-1671, Timely Initiation of CRs. This NCV is identified as 50-324/99-04-02, Failure to Promptly Identify Conditions Adverse to Quality.

c.

Conclusions A violation was identified for the failure of the licensee to initiate CRs for trips of the reactor protection system and the manipulation of a component in the control room without proper authorization. A negative trend in the identification of nonconforming conditions was identified based on these findings, as well as licensee and third-party assessments.

O7.2 Operations Self-Assessments and Audits (40500)

19 Recent NRC Inspection Reports and the Plant Performance Review dated March 23, 1999, identified a decline in routine operation performance. As part of this inspection, the inspectors reviewed licensee actions to address the declining performance. The inspectors noted that the licensee had completed one site-wide human performance assessment in 1999 that included operations. In addition, operations management had initiated Operations Shift Improvement Plans. The plans, completed for each operating crew, provided a method to implement shift expectations, overall management expectations, and areas for improvements. The plans were the foundation for the corrective actions associated with shift operations. Deficiencies identified by the NRC were included in the corrective action program. Additionally, the licensee had 10 benchmarking trips planned throughout the nuclear industry in 1999 to evaluate and implement industry best practices.

The inspectors reviewed a schedule of completed corrective actions and observed that the majority of the action items had been completed and closed. The significant items remaining open were the follow-up effectiveness reviews to verify the completeness and acceptance of the corrective actions. There were seven self-assessments and effectiveness reviews scheduled for the remaining year.

The inspectors concluded that the licensee had taken appropriate actions to improve overall operations performance. The completed corrective actions, planned benchmarking trips, and effectiveness reviews were reasonable.

O8 Miscellaneous Operations Issues (92901)

O8.1 (Closed) Licensee Event Report (LER) 50-324/99-04: Reactor Recirculation System Bypass Valve Inoperability Results in Operation Prohibited by Technical Specifications.

During the May 1999 Unit 2 refueling outage, the B loop reactor recirculation system bypass valve, 2-B32-F032B, was disassembled to determine the cause of periodic binding and consequent valve electrical circuit trip on thermal overload of the actuator motor. A valve vendor expert was present during this disassembly. It was found, upon disassembly, that a wedge spring (which was designed to minimize binding) and a spring retainer plate were missing. According to plant drawings, these components should have been located between the valve discs. The licensees root cause investigation determined that the valve binding was due to a combination of these missing components and valve internal component tolerances. These conditions together caused the valve to randomly bind during stroking.

The licensee and vendor expert examined the valve further in order to determine whether the missing components had been dislodged from the valve during operation or whether they had not been installed. The valve expert documented that the missing wedge spring and retainer plate did not pass by the valve seat discs because no damage or wear indications were present which would have indicated this. Thus, the as-found condition of the valve upon disassembly indicated that the valve was reassembled incorrectly during previous work on the valve. The licensee determined that in 1989 the valve manufacturer had been contracted to modify the valve packing on

20 2-B32-F032B. The valve was completely disassembled at that time by the contractor for inspection. The inspectors noted that the work package did not specify step-by-step instructions for assembly of the wedge pack (which included the wedge spring and retainer plate). Because the valve had been randomly binding since that time, the licensee concluded that the valve had been inoperable since the 1989 maintenance.

The valve had been stroked to meet TS surveillance requirements a total of 15 times since the valve was worked on in 1989. The valve stroked three times before failure in August 1990. When the valve failed to stroke closed in August 1990, the licensee stroked the valve many times satisfactorily. The licensee determined that any mechanical interference must have been polished away and performed no other corrective actions. The valve stroked successfully nine more times before failure in August 1998. When the valve failed to stroke closed in August 1998 the motor actuator spring pack, located in the motor-operated valve (MOV) actuator, was replaced. The spring pack had grease packed in the spring where it should not have; however no metal was found in the grease to point specifically to the spring pack as being the cause of the failure. Post maintenance testing, which included cycling the valve manually and electrically several times, revealed no problems with the valve. A period of time after the plant restarted, a work order was generated to inspect the valve in the 1999 Unit 2 refueling outage. The valve was not stroked again until March 29, 1999. The valve failed to stroke on that day. When the valve failed to stroke in March 1999 the valve was closed to ensure the low pressure coolant injection (LPCI) system safety function was maintained because the valves operability was questioned. Corrective actions were taken but did not find a probable root cause until the May 1999 Unit 2 refueling outage. During the May 1999 Unit 2 refueling outage the actuator for the valve was disassembled, rebuilt, and no problems were found with the actuator. The valve was then disassembled and the root cause determined.

The licensee determined that if the valve were open during LPCI injection, flow would be diverted from the core, thus affecting LPCI function. Licensee engineering calculations (2-B32-0007, Reactor Recirculation Pump Bypass Line Flow) showed that with the valve fully open, approximately 1173 gallons per minute (gpm) would have gone through the bypass line. TS requires a LPCI injection flow of 14,000 gpm with two pumps running. System flow testing showed a margin of approximately 3000 gpm over the TS-required flow for the LPCI B subsystem (resulting in 17,000 gpm flow). The inspectors reviewed and verified the licensees engineering calculations and system flow test data.

Therefore, the excess LPCI flow margin would fully mitigate the effect of the open valve and therefore adequate core injection would be maintained. However, the TS Bases state that if this valve is inoperable and in the open position, the associated low LPCI subsystem must be declared inoperable.

TS 3.5.1, Emergency Core Cooling Systems (ECCS) And Reactor Core Isolation Cooling (RCIC) System, requires that each ECCS subsystem, including the LPCI system, shall be operable while in modes 1, 2, and 3. Limiting Condition for Operation (LCO) Action A requires that when one low pressure ECCS injection/spray subsystem is inoperable, the subsystem must be restored within seven days.

21 Contrary to the above, from 1989 until March 30, 1999, the B LPCI subsystem was inoperable for greater than the LCO allowed action time because reactor recirculation system discharge bypass valve 2-B32-F032B was inoperable. This valve was inoperable because its wedge spring and spring retainer plate had not been installed, causing valve binding specifically on three occasions, which prevented the valve from closing. This Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensees corrective action program as CR 99-0775, 2-B32-F032B Stroke Failure. This NCV is identified as 50-324/99-04-03, Reactor Recirculation Discharge Bypass Valve Inoperability.

II. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities

a.

Inspection Scope (61726, 71707)

The inspectors reviewed all or portions of the following surveillance tests and/or maintenance work requests/job orders (WR/JOs):

Periodic Test 1PT-24.1-1, Service Water Pump and Discharge Valve Operability Test, Rev. 39, Periodic Test 0PT-1.7, RPS Automatic Scram Contactor Test, Rev. 2, Maintenance Surveillance Test 2MST-HPCI27Q, HPCI and RCIC Low Water Level Instrument Channel Cal, Rev. 4.

WR/JO 99-ADSP1, Repair of 2A RCR Tachometer WR/JO 98-ABTG1, Mechanical Seal Replacement on the 2B RCR Pump

b.

Observations and Findings The inspectors observed that effective supervisory oversight was provided. They also verified that procedures used were of the proper revision and that test equipment was within the current calibration cycle. The inspectors reviewed the applicable TS and verified compliance with the regulations. Satisfactory three-part communications were observed in the control room.

During the pre-job briefing for the repair of the 2A RCR tachometer, the sequence of activities was comprehensively reviewed. The review included a thorough discussion of the operating procedure. Questions and concerns posed by the technicians were resolved. The inspectors also reviewed the WR/JO close-out package for the mechanical seal replacement on the 2B RCR pump (WR/JO 98-ABTG1). The work package included a detailed log of work activities that was updated at the end of each shift to ensure proper documentation of the work for this job because a turnover from shift to shift was required. The work instructions were of sufficient detail and included

22 special instructions for work inside the drywell in a high radiation area. The completed maintenance procedure was attached to the package and contained the required data entries and signatures, as well as quality control hold point signatures. The inspectors found that the close-out package was complete with the appropriate supervisory reviews completed.

c.

Conclusions Maintenance activities observed were performed consistent with the applicable procedures, which were verified to be of the proper revision and implemented using the correct level-of-use. Three-part communications were observed. Test equipment was verified to be within the current calibration cycle.

M2.1 Failed Fuel Bundle Inspection

a.

Inspection Scope (62707)

The inspectors observed the inspection of a failed fuel bundle removed from Unit 2 during the recent refueling outage.

b.

Observations and Findings On June 16, the inspectors observed underwater video inspection activities conducted in the Unit 2 spent fuel pool. The activities were well planned and carefully executed.

The inspectors noted ample health physics support with an emphasis on exposure reduction throughout the work. Foreign material exclusion area procedures were in effect and maintained control of all material and equipment going into the area around the spent fuel pool.

The licensee identified that a single fuel rod had multiple axial cracks totaling approximately 120 inches long. Early identification and effective suppression resulted in cracks that were narrow with no visible fuel and no indication of fuel pellet washout.

There was a discernable fret mark located on the fuel rod at a position 121 inches from the bottom of the rod, at the sixth fuel rod spacer. No debris was located at the site of the fretting. The licensee, in conjunction with the fuel vendor, is performing a root cause analysis to determine the cause of the fretting and subsequent fuel failure.

c.

Conclusions The licensee identified that a single fuel rod had multiple cracks totaling approximately 120 inches long. Early identification and effective suppression resulted in cracks that were narrow. A discernable fret mark was noted, although no debris was located at the site of the fretting. The failed fuel inspection activities were well planned with ample health physics support including an emphasis on exposure reduction during the work.

23 M2.2 Foreign Material Exclusion (FME) Controls During Unit 2 Refueling Outage

a.

Inspection Scope (62707)

The inspectors reviewed FME controls and associated issues during the Unit 2 refueling outage.

b.

Observations and Findings The inspectors found that the licensee generated 15 CRs for foreign material found in FME areas and for improper implementation and control of FME areas. Four of the CRs were generated for foreign material that was found in the reactor vessel and four CRs were generated for foreign material that was found in the spent fuel pool. Lost parts analyses were performed for two items that were left in the reactor vessel. The foreign material was left in the reactor vessel either because it could not be found after it was sighted or because it was not successfully retrieved. One of the items was debris that was found near jet pump number 4 during vessel inspections. The lost parts analysis for corrosion products and a small piece of wire determined that they could potentially cause fretting wear on the fuel cladding if the debris filters on the fuel bundles did not filter out the small particles. The analysis indicated that the fretting wear could potentially lead to cladding breach. The analysis concluded that a cladding breach would be indicated by identification of increased fission product release via normal parameter monitoring. The analysis justified this condition by stating that the release would be limited by performing power suppression around the affected bundles and possibly imposing operating restrictions on the plant. The inspectors found that the same conclusions were reached in the lost parts analysis for the second item left in the reactor vessel which was an unaccounted machine screw that had fallen off the refueling bridge. The screw was 6-32 x 1/4 inch in size.

During the last Unit 1 refueling outage, the inspectors reviewed FME controls and identified a weakness in spent fuel pool inventory and control, discussed in NRC Inspection Report 50-325(324)/98-06, Section M2.3. This was primarily due to a thermocouple wire that was unknowingly transferred from the fuel pool to the reactor vessel. During the current inspection, the inspectors found that the licensee maintained adequate inventory and control over known items in the fuel pool but had not inventoried items under the fuel racks. The licensee explained to the inspectors that those items do not interfere with the fuel bundles in the fuel racks as they verify storage positions periodically with a camera. The licensee found a piece of a control rod blade in a storage rack location while attempting to place a fuel bundle in the same location. The inspectors found that no fuel bundle had been stored in that location since the existing control rod had been cut up for disposal. Control of foreign material in FME areas remained a challenge during the Unit 2 refueling outage. Corrective actions implemented by the licensee for the above issues were appropriate.

24

c.

Conclusions Control of foreign material in FME areas remained a challenge during the Unit 2 refueling outage. Eight foreign material items were found to be in the reactor vessel and the fuel pool during the Unit 2 refueling outage. Corrective actions implemented by the licensee for foreign materials in the reactor vessel and the fuel pool were effective in minimizing the risk to fuel integrity.

III. Engineering E2 Engineering Support of Facilities and Equipment E2.1 Thoroughness of Documentation For Maintenance Work Issues (37551)

The inspectors reviewed the licensees corrective action process during the Unit 2 refueling outage for two conditions that were found by the licensee to be related to improper maintenance conducted by vendor contractors. One issue involved incorrect configuration of MOV wire jumpers. The licensee found that wire jumpers were not installed correctly on two service water system valves. The valves were required to shut during a loss-of-coolant accident scenario; however the licensee determined that the valves would have performed their intended function even with the incorrect jumper configuration. This condition was attributed to incorrect vendor contractor work. The licensee additionally found that a jumper wire was not installed on the 2-E11-F024B, torus cooling isolation valve. This valve was worked on by vendor contractors in the early 1990s. In addition, the vendor had performed work on 11 other MOVs in both the RHR and HPCI systems. However, the licensee determined that for all of these other valves, the incorrect jumper configuration that potentially could have existed would not have impaired their intended safety function. MOV testing to determine the as-found condition of the 2-E11-F024B valve indicated that sufficient margin existed in the valve operating parameters such that there were no safety consequences with not having the jumper installed.

The other issue that the inspectors reviewed involved the inoperability of the B loop reactor recirculation system discharge bypass valve, 2-B32-F032B. The vendor determined that the condition was caused by improper vendor contractor work performed in 1989. This inoperability was discussed in Section O8.1 of this report.

The inspectors found after a review of all the licensees documentation that the licensee did not address or disposition the identified problem with vendor contractor work at the facility. As a result, corrective actions to prevent recurrence were not formulated.

When the inspectors notified licensee personnel of this shortcoming, they recognized that they had not addressed the issue and stated that revisions would be made to the appropriate documentation. The licensee had recently changed its control of vendor contractor work to require that individuals be qualified in Brunswicks quality assurance program, that the vendor use Brunswick facility procedures, and that a Brunswick project manager be assigned to each work task. The licensee stated that in the past, vendor work activities were not always monitored such that quality standards were achieved.

25 E8 Miscellaneous Engineering Issues (92903)

E8.1 (Closed) Licensee Event Report 50-325(324)/99-05: Control Room Emergency Ventilation System Surveillance Inadequacy. This event was previously identified and dispositioned in NRC Inspection Report 50-325(324)/99-02. The inspectors noted that immediate corrective actions were complete. Long-term corrective actions to address the adequacy of the licensees response to Generic Letter (GL) 96-01, Testing of Safety-Related Logic Circuits, were not addressed in the LER. The inspectors identified that the review of the adequacy of the licensees response to GL 96-01 was an action item associated with CR 99-844, CREV Logic Missed Surveillance. This action was scheduled for completion on June 30, 1999. The inspectors verified that this action was scheduled in the licensees corrective action program and that the other actions were satisfactorily completed.

E8.2 Year 2000 (Y2K) Readiness Program Review: The staff conducted an abbreviated review of Y2K activities and documentation using Temporary Instruction (TI) 2515/141, Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants.

The review addressed aspects of Y2K management planning, documentation, implementation planning, initial assessment, detailed assessment, remediation activities, Y2K testing and validation, notification activities, and contingency planning. The reviewers used NEI/NUSMG 97-07, Nuclear Utility Year 2000 Readiness, and NEI/NUSMG 98-07, Nuclear Utility Year 2000 Readiness Contingency Planning, as the primary references for this review. During the review, the licensee stated that the Y2K Readiness Project activities and contingency planning were about 99 percent complete, and that both programs were on target to be completed by their scheduled due dates.

Installation and testing of the digital feedwater control system for Unit 2 had been completed. Unit 1 was scheduled for this same modification in the Fall of 1999. The licensee planned to enter a forced outage to accomplish this modification by November 16, 1999. This schedule had been previously discussed with the NRC and is documented in the Y2K Audit Report conducted at the Brunswick site on October 6-9, 1998.

Conclusions regarding the Y2K readiness of the facility are not included in this report.

The results of this review will be combined with the results of reviews of other licensees in a summary report to be issued by July 31, 1999.

IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)

Health physics support for a tour of the drywell was excellent. The use of individual radio headsets and remote-indicating dosimetry facilitated coordination with the technicians outside the drywell monitoring the inspection activities. This coordination

26 allowed personnel in the drywell to reduce the time spent in high dose rate areas and thereby reduce personnel exposure. Effective health physics support with an emphasis on exposure reduction was observed throughout the fuel inspection on Unit 2, as well as during the routine outage maintenance activities. All locked high radiation doors challenged were properly labeled and locked.

R1.2 Radiological Work Controls

a.

Inspection Scope (83750)

The inspectors observed Radiation Protection (RP) activities. The inspection included reviews of records and procedures, interviews with licensee personnel, and observations of work activities in progress.

b.

Observations and Findings Independent radiation surveys made by the inspectors were in agreement with the licensees radiation survey results. The radiological postings were adequate for areas surveyed. All locked high radiation area doors checked by the inspector were secured properly. The licensee maintained control of keys to locked high radiation and very high radiation areas.

There was good RP coverage at the main radiological control area entrance and exit portals, and the inspectors observed good interactions and communications between radiation workers and RP personnel.

Ten radiation workers were interviewed by the inspectors in the radiation control area concerning their knowledge of dosimeter alarm levels. The inspectors found that approximately one half of the workers did not know their dosimeter alarm set points specified on the radiation work permits they were using. However, all personnel interviewed reported that they would leave the work area and contact the RP staff if their dosimeter alarmed.

c.

Conclusions Licensee radiation surveys, postings, access controls, and radiological work controls were effective and were performed in accordance with regulatory requirements. About half of the ten radiation workers questioned concerning knowledge of their dosimetry alarm setpoints did not know their alarm setpoints.

R1.3 As Low As Reasonably Achievable (ALARA)

a.

Inspection Scope (83750)

This review was made to assess licensee performance with respect to maintaining individual and collective radiation exposures ALARA during the Unit 2 Refueling Outage.

27

b.

Observations and Findings Individual occupational radiation worker doses remained low, with the highest internal and external radiation doses well below the licensees administrative limits and regulatory requirements.

Licensee goals for the Unit 2 RFO included a collective radiation dose goal less than 198 person-rem. The licensee utilized a systematic process to prepare ALARA plans for specific RFO tasks. Selected ALARA plans were reviewed and the inspectors found the plans included processes and controls to reduce collective occupational radiation exposures. In general, the licensee was meeting dose goals for most ALARA plans.

However, the licensee had significant emergent work and projected exceeding the outage goal by approximately 55 to 60 person-rem.

Management support for the ALARA program was demonstrated by the allocation of significant resources for the permanent construction of steel shielding above the Unit 1 moisture separator re-heater and crossover pipe. The licensee projected a collective dose savings of approximately 50 person-rem per year as a result of the plant modification. The licensee also cooled the Unit 1 reactor building, aiding worker efficiency and minimizing personnel contamination events.

c.

Conclusions Individual radiation doses were well below regulatory limits. The Brunswick ALARA program reduced site collective personnel radiation doses for planned activities.

28 V. Management Meetings XI Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on June 25, 1999. The licensee acknowledged the findings presented. No proprietary information was identified.

29 PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Security Manager K. Crocker, Superintendent, Environmental and Radiation Control D. Dicello, Environmental and Radiation Control E. Quidley, Maintenance Manager N. Gannon, Operations Manager J. Gawron, Nuclear Assessment Manager M. Herrell, Training Manager K. Jury, Regulatory Affairs Manager J. Keenan, Site Vice President B. Lindgren, Site Support Services Manager J. Lyash, Plant General Manager G. Miller, Brunswick Engineering Support Manager S. Tabor, Project Analyst, Regulatory Affairs S. Vann, Outage and Scheduling Manager 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 71001:

Licensed Operator Requalification Program Evaluation IP 71707:

Plant Operations Program IP 71715:

Sustained Control Room and Plant Observations IP 71750:

Plant Support Activities IP 83750:

Occupational Radiation Exposure IP 92901:

Followup - Operations IP 92903:

Followup - Engineering TI 2515/141: Y2K Readiness Review

30 ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-324/99-04-01 NCV Failure to Follow Procedure Results in Condensate System Transient (Section O4.4).

50-324/99-04-02 NCV Failure to Promptly Identify Conditions Adverse to Quality (Section O7.1) 50-324/99-04-03 NCV Reactor Recirculation Discharge Bypass Valve Inoperability (Section O8.1)

Closed 50-324/99-04-01 NCV Failure to Follow Procedure Results in Condensate System Transient (Section O4.4).

50-324/99-04-02 NCV Failure to Promptly Identify Conditions Adverse to Quality (Section O7.1) 50-324/99-04-03 NCV Reactor Recirculation Discharge Bypass Valve Inoperability (Section O8.1) 50-324/99-04 LER Reactor Recirculation System Bypass Valve Inoperability Results in Operation Prohibited by Technical Specifications (Section O8.1) 50-325(324)/99-05 LER Control Room Emergency Ventilation System Surveillance Inadequacy (Section E8.1)