IR 05000454/1999012

Insp Repts 50-454/99-12 & 50-455/99-12 on 990803-0916.One NCV Occurred.Major Areas Inspected:Operations,Engineering, Maint/Surveillance & Plant Support

ML20217F807
Person / Time
Site:	Byron
Issue date:	10/08/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217F794	List: IR 05000454/1999012 ML20217F789
References
50-454-99-12, 50-455-99-12, NUDOCS 9910210083
Download: ML20217F807 (19)

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U. S. NUCLEAR REGULATORY COMMISSION REGION lil Docket Nos: 50-454;50-455 License Nos: NPF-37; NPF-66 Report No: 50-454/99012(DRP); 50-455/99012(DRP)

Licensee: Commonwsalth Edison Company Facility: Byron Generating Station, Units 1 and 2 Location: 4450 N. German Church Road Byron,IL 61010 Dates: August 3 - September 16,1999 Inspectors: E. Cobey, Senior Resident inspector B. Kemker, Resident inspector C. Thompson, Illinois Department of Nuclear Safety Approved by: Michael J. Jordan, Chief Reactor Projects Branch 3 Division of Reactor Projects 9910210083 991008'

PDR ADOCK 05000454 G PDR

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EXECUTIVE SUMMARY Byron Generating Station Units 1 and 2 NRC Inspection Report 50-454/99012(DRP); 50-455/99012(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of inspection activities by the resident staf Ooerations

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Operators responded appropriately to alarms, closely monitored main control room panels, were knowledgeable of plant conditions, and generally used three-way ,

communications, in addition, shift tumover briefings were appropriate, emphasizing plant status, existing limiting conditions for operation, and scheduled maintenance and surveillance testing activities, with one notable exception. (Section 01,1)

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The licensee's response to a minor earthquake, which occurred approximately 30 miles i from Byron Station, was appropriate. Operators walked down all accessible plant areas, ,

checked plant structures and equipment. and identified no equipment damag {

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The licensee failed to control the configuration of the Unit i reactor coolant rg.oap system in accordance with Byron Operating Procedure CV-6, " Operation of the Reactor J Makeup System in the Borate Mode," Revision 11. In addition, the licensee did not enter the event into its corrective action program until 16 days after the event due to the operating shift management's failure to implement the process for responding to operational configuration control occurrences. One example of a Non-Cited Violation was issued. (Section O2.1)

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The licensee failed to control the configuration of a freeze seal following maintenance on the Unit 2 component cooling water system. This was due to the failure to follow Byron Administrative Procedure 330-1, " Station Equipment Out-Of-Service Procedure,"

Revision 30, and inadequate communications between maintenance and operations department personnel. Consequently, approximately 200 gallons of water inadvertently drained from the system. One example of a Non-Cited Violation was issue (Section O2.2)

Maintenance / Surveillance

. The inspectors concluded that the observed surveillance tests were performed wel Specifically, the surveillance tests satisfied the requirements of the Technical j Specifications (TS); and each of the tested components met their respective acceptance l criteria and remained operable with the exception of the train B containment spray engineered safety features actuation system relay K-643, which the licensee repaired within the TS allowed outage time. (Section M1.1)

. The licensee did not implement effective foreign material exclusion controls at the river screen house, which resulted in the fouling of the first stage of the OB circulating water system makeup pump with a rubber hose. In addition, the licensee's corrective actions for this event were narrowly focused and did not address the licensee's process for implementing foreign material exclusion controls for normally open areas susceptible to

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intrusion of foreign materials like the river screen house. No violation of regulatory requirements occurred since the deficiency involved the non-safety related circulating water system. (Section M2.1)

Enaineerina

.- The licansee did not complete one of the corrective actions for Licensee Event Report 50-454/98-018, " Inoperable Unit 1 Diesel Generator Due to Low Lube Oil Pressure Condition," in a timely manner due to insufficient engineering management oversight of the activity. The corrective action involved evaluating the use of one of two parallel lube oil strainers at a time to preclude the simultaneous clogging of both lube oil i strainers and revising the procedures and drawings necessary to modify the system operation. (Section E7.1) -

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Nuclear Oversight's evaluation and response to the continuing deficiencies with the implementation of the engineering design modification process was appropriate and i indicative of a self-critical oversight organization. (Section E7.2)

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Plant Suooort

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The inspectors concluded that radiologically controlled areas we"e properly posted and controlled with one minor exception. The inspectors also concluded that improvements in the licensee's as-low-as-reasonably-achievable controls had resulted in notable reductions in the licensee's accumulated dose. (Section R1.1)

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Report Details Summary of Plant Status

- The licensee operated Units 1 and 2 at or near full power for the duration of this inspection perio I, Operations 01 Conduct of Operations 01.1 General Comments (71707)

During this inspection period, the inspectors routinely observed the conduct of plant operations from the control room. The inspectors noted that operators responded appropriately to alarms, closely monitored main control room panels, were -

knowledgeable of plant conditions, and generally used three-way communications. The inspectors also noted that shift tumover briefings were appropriate, emphasizing plant status, existing limiting conditions for operation, and scheduled maintenance and surveillance testing activities, with one notable exception. On August 17,1999, the inspectors noted that most Nuclear Station operators and non-licensed operators did not participate in the shift tumover briefing; specifically, when asked to discuss the plant status as it pertained to their job responsibilities, most of the operators indicated that they had nothing to add to the briefing.- Consequently, the effectiveness of the turnover briefing was diminished. As a result, the inspectors expressed a concem with operations management regarding the effectiveness of the shift turnover briefing with minimal participation by the operators. in response to the inspectors' questions, i operations management addressed the issue with each shift and modified the format of the briefing. Subsequent shift tumover provided a better understanding of plant status to all attendees.

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01.2 Acorooriate Licensee Response to Seismic Event i Insoection Scope (93702)

The inspectors responded to the control room and observed the licensee's response to a minor earthquake which occurred approximately 30 miles from Byron Station. The inspectors interviewed operations department personnel and reviewed the Generating Station Emergency Plan, the Updated Final Safety Analysis Report (UFSAR), and Byron Abnormal Operating Procedure (BOA) ENV-4, " Earthquake Unit 0," Revision 53 ~ Observations and Findinos l At 11:17 a.m. on September 2,1999, an earthquake of magnitude 3.5 on the Richter Scale occurred approximately 30 miles from Byron Station. Some minor tremors were felt by personnel on-site and were reported to the control room. Seismic monitoring equipment in the control room did not detect the earthquake. In response to the event, operators confirmed that an earthquake had occurred with the National Earthquake Information Center in Golden, Colorado and entered BOA ENV- r

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I The inspectors reviewed the Generating Station Emergency Plan with the shift manager and concurred with his conclusion that the earthquake did not exceed established criteria for declaration of an Unusual Event. The inspectors observed main control room operations during portions of the event and concluded that the response by station ,

personnel to the event was appropriate. Operators walked down all accessible plant areas, checked plant structures and equipment, and identified no damage or abnormal indication Engineering personnel retrieved tri-axial peak accelerograph data from seismic .

monitoring equipment in the plant, which did not detect any seismic activity. The licensee subsequently tested and verified that the seismic monitoring equipment was I operable. Engineering personnel performed a calculation to equate an earthquake with I a magnitude of 3.5 on the Richter Scale, locaid approximately 5 kilometers below '

ground, to acceleration as a fraction of the acceleration due to gravity (g). The result was 0.005g. An earthquake of this magnitude was below the station's seismic monitoring system minimum detection threshold of 0.02 i In response to local media interest, the site vice president met briefly with members of 1 the press to address their questions. As a result, the licensee made a 4-hour non-emergency report to the NRC in accordance with 10 CFR Part 50.72(b)(2)(vi). Conclusions The licensee's response to a minor earthquake, which occurred approximately 30 miles from Byron Station, was appropriate. Operators walked down all accessible plant areas, checked plant structures and equipment, and identified no equipment damag O2 Operational Status of Facilities and Equipment 1 O2.1 Boric Acid Flow Potentiometer Misoositioned Inspection Scope (71707)

The inspectors reviewed the circumstances surrounding the failure of operators to correctly align the Unit 1 reactor coolant makeup system (RCMS) in auto makeup mode following a batch addition of boric acid to the reactor coolant system (RCS). The inspectors interviewed operations department personnel and reviewed the following ,

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• Byron Operating Procedure (BOP) CV-6," Operation of the Reactor Makeup System in the Borate Mode," Revision 11

. BOP CV-7,." Operation of the Reactor Makeup System in the Auto Makeup or Manual Mode," Revision 10

. BOP CV-8, "CV [ Chemical and Volume Control] System Mixed Bed / Cation Demineralizer Operation," Revision 20

. Common Work Practice Instruction (CWPI) NSP-OP-1-20, " Operational ,

Configuration Control," Revision 1 1

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b. Observations and Findinas On August 8,1999, operators failed to correctly align the Unit 1 RCMS in the auto makeup mode following a batch addition of boric acid to the RCS. While adding boric acid to the RCS in accordance with BOP CV-6, operators adjusted the boric acid flow potentiometer to maximum. Operators then failed to reset the potentiometer for the boron concentration in the RCS following the boric acid addition as directed by the procedure. On the following shift during the performance of BOP CV-8, the operators identified that the potentiometer was not properly set for the current RCS boron concentration and adjusted it per procedure. There was no adverse consequence to the plant as a result of this error since an auto makeup to the volume control tank had not occurred while the potentiometer was incorrectly se The inspectors reviewed the system operation with operations department personnel and noted that had there been a need for an auto makeup to the volume control tank while the pctentiometer was set at maximum, the boric acid concentration subsequently added to the Volume Control Tank and thus the RCS would have been greater than the boric acid concentration in the RCS. The resultant transient would have been negative reactivity added to the reactor which would have resulted in a negative temperature transient and caused operators to reduce power to offset the temperature decreas The inspectors reviewed BOP CV-6 and noted that Step D.3 of the procedure stated that during normal reactor operation, except during boration or dilution, the RCMS should be operated in the auto makeup mode with the boron concentration adjusted to equal the concentration in the RCS. In addition, BOP CV-6, Step F.18, required operators to return the RCMS to the auto makeup mode with a setting for the new boron concentration per BOP CV-7. However, operators did not utilize BOP CV-7 when returning the RCMS to the auto makeup moce. Consequently, the operators failed to reset the boric acid flow potentiomete Technical Specification (TS) 5.4.1.a states that written procedures shall be established, implemented, and maintained for procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, specifies operation of the chemical and volume control system as an example of a pressurized water reactor system operating >

procedure. Byron Operating Procedure CV-6," Operation of the Reactor Makeup System in the Borate Mode," Revision 11, is one of the chemical and volume control system operating procedures. The operators' failure to correctly align the Unit 1 RCMS in the auto makeup mode following a batch addition of boric acid to the RCS per '

BOP CV-6, step F.18, is an example of a violation of TS 5.4.1.a. This Severity Level IV violction is being treated as a Non-Cited Violation, consistent with Appendix C of the {

NRC Enforcement Policy (50-454/455-990012-01a(DRP)). This issue is in the l licensee's corrective action program as problem identification form (PlF) B1999-304 I The inspectors were concerned that a PIF had not been written to enter this event into l the licensee's corrective action program until 16 days after it occurred and that, until that j time, sen!or licensee management was unaware that the event had occurred. In addition, the inspectors were concerned that the event may not have been entered into the licensee's corrective action program had it not been for an operator involved with the event initiating a PIF when he returned to work following his vacation. Inasmuch as the event could have resulted in a reactivity transient had the mis-positioned potentiometer

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not been identified before an auto makeup to the volume control tank occurred, the inspectors were concerned that operating shift management did not recognize the potential significance of the event. The inspectors noted that neither shift manager involved with the event ensured that a PlF was written as required by CWPI-NSP-OP-1-20 and neither shift manager notified senior licensee management of the event. The inspectors discussed the operating shifts' response to the event with senior licensee management. The inspectors concurred with senior licensee

management's conclusion that operating shift management did not appropriately implement the licensee's process for responding to operational configuration control occurrences. At the end of this inspection period, the licensee was performing an apparent cause evaluation of this event for review by the licensee's Corrective Action Review Boar Conclusions The licensee failed to control the configuration of the Unit i reactor coolant makeup system in accordance with Byron Operating Procedure CV-6, " Operation of the Reactor Makeup System in the Borate Mode," Revision 11. In addition, the licensee did not

. enter the event into its corrective action program until sixteen days after the event due to the operating shift management's failure to implement the process for responding to operational configuration control occurrences. One example of a Non-Cited Violation was issue .2 Failure to Follow the Out-Of-Service Procedure and inadeauate Communications Resulted in an inadvertent Drainina of Water from the Unit 2 Component Coolina Water System insoection Scope (71707)

The inspectors reviewed the circumstances surrounding an inadvertent draining of approximately 200 gallons of water from the Unit 2 component cooling water system during system restoration following maintenance. The inspectors interviewed operations department personnel and reviewed the following document * Byron Administrative Procedure (BAP) 330-1, " Station Equipment Out-Of-Service Procedure," Revision 30

. Byron Mechanical Maintenance Procedure (BMP) 3300-7, " Application of Freeze Seal to All Piping," Revision 13

- Work Request 980135649-02, " Perform Freeze Seal to Support Valve Repair" Observations and Findinas l q

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On August 20,1999, following maintenance to repair the Unit 2 CC system chemical addition tank inlet isolation valve (2CC2092), mechanical maintenance personnel removed a freeze seal which had been installed to provide system isolation for the wor Shortly after the freeze seal was removed, operators identified that the Unit 2 CC system chemical addition tank drain valve (2CC094) had been left open when a portion of the system affected by the maintenance was initially drained. Approximately 200 gallons of water drained from the system before operators closed the drain valv No equipment was damaged as a result of this even U

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h The inspectors noted that performance of the maintenance activity required the use of an " exceptional out-of-service," which specified the use of a freeze seal to isolate a portion of the system affected by the maintenance from the remainder of the CC system. The inspectors reviewed the out-of-service and noted that the freeze seal was not controlled as part of the out-of-service for the maintenance activity (the freeze seal was not carded), although it was listed on the out-of-service checklist and its installation was sequenced when the out-of-service was established. The inspectors also noted that the drain valve was carded as part of the out-of-service with instructions to "use as necessary to drain tank." However, the out-of-service did not require the drain valve to be closed and operators did not close the valve following system drainin Consequently, when the freeze seal was removed, water filled the piping and came out of the open drain valve. Operators in the control room were alerted to the condition by an alarm when the Unit 2 CC surge tank automatic make-up valve opened. Although control room operators were aware that the freeze seal was being removed, the alarm was unexpected because the volume of the system originally drained for the maintenance was relatively small compared to the volume of the surge tan The inspectors reviewed the licensee's prompt investigation which concluded that the freeze seal was removed by mechanical maintenance personnel without formal operations department approval. The investigation identified that inadequate verbal communications between mechanical maintenance personnel and the work execution center as well as imprecise wording in BMP 3300-7 contributed to the event. The investigation additionally identified that the out-of-service was inadequate, in that, the drain valve should have been closed during the out-of-service. The investigation recommended that BMP 3300-7 be revised to require control of the freeze seal with an out-of-service card and an operations signature to approve the removal of the freeze sea The inspectors reviewed BMP 3300-7 and noted that Step F.7.c of the procedure required mechanical maintenance personnel to contact the shift manager to determine valve positions inside of the freeze boundary prior to removing the freeze seal. The licensee ' identified that although mechanical maintenance personnel contacted the work execution center prior to removing the freeze seal, they did not request that the operators determine valve positions inside of the freeze boundar The inspectors also reviewed BAP 330-1 and noted that Step C.2.n of the procedure required, in part, that for return to service purposes, non-carded items shall be handled as carded items for sequencing, return to service positions, and appropriate sign-off However, the operators failed to sequence the removal of the freeze seal, which was a non-carded item, with the retum to service positions of the other carded and non-carded items on the out-of-service, such as the drain valv Technical Specification 5.4.1.a states that written procedures shall be established, implemented, and maintained for procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A of Regulatory

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Guide 1.33, Revision 2, February 1978, 6,.ecifies equipment control (e.g., locking and tagging) as an example of an administrative procedure. Byron Administrative Procedure 330-1," Station Equipment Out-Of-Service Procedure," Revision 30, administers the system / equipment out-of-service program at Byron Station. The licensee's failure to sequence the non-carded freeze seal during the return to service following ri,aintenance on the Unit 2 component cooling water system chemical addition

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tank inlet isolation valve as required by BAP 330-1, step C.2.n, is an example of a violation of TS 5.4.1.a. This Severity Level IV violation is being treated as a Non-Cited Violation, conslatent with Appendix C of the NRC Enforcement Policy

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(50-454/455-990012-01b(DRP)). This violation is in the licensee's corrective action program as PlF B1999-295 Conclusions

' The licensee failed to control the configuration of a freeze seal following maintenance on the Unit 2 component cooling water system. This was due to the failure to follow Byron Administrative Procedure 330-1, " Station Equipment Out-Of-Service Procedure,"

Revision 30, and inadequate communications between maintenance and operations department personnel. Consequently, approximately 200 gallons of water inadvertently drained from the system. One example of a Non-Cited Violation was issue . Maintenance M1 Conduct of Maintenance M1.1 Surveillance Test Observations i Inspection Scope (61726)

The inspectors interviewed operations, engineering, and maintenance department personnel; reviewed the completed test documentation and applicable portions of the Updated Final Safety Analysis Report and Technical Specifications; and observed the performance of selected portions of the surveillance test procedures listed belo . 2BOSR 3.2.7-602A Unit Two ESFAS [ Engineered Safety Features Actuation System] Instrumentation Slave Relay Surveillance (Train A Automatic Safety injection - K602, K647)

• 2BOSR 3.2.7-640A Unit Two ESFAS Instrumentation Slave Relay Surveillance (Train A Turbine Trip - K640)

+ 2BOSR 3.2.7-643B Unit Two ESFAS Instrumentation Slave Relay Surveillance (Train B Automatic Containment Spray - K643)

+ 2BOSR 8.1.2-2 Unit Two 28 Diesel Generator Operability Monthly (Staggered) and Semi-Annual (Staggered) Surveillance

. 2BVSR 5.5.8.AF.1-2 Unit 2 ASME [American Society of Mechanical Engineers)

Surveillance Requirements for the Diesel Driven Auxiliary Feedwater Pump Conclusions The inspectors concluded that the observed surveillance tests were performed wel Specifically, the surveillance tests satisfied the requirements of the Technical Specifications (TS); and each of the tested components met their respective acceptance criteria and remained operable with the exception of the train B containment spray .

engineered safety features actuation system relay K-643, which the licensee repaired within the TS allowed outage tim l

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/ M2 -. Maintenance and Material Condition of Facilities and Equipment M2.1 Forelan Material Exclusion Practices at the River Screen House a. - Insoection Scooe (62707)

The inspectors reviewed the licensee's foreign material exclusion (FME) recovery plan after a 20 foot length of hose was found entangled in the first stage of the OB circulating water (CW). system makeup pump. The inspectors reviewed the results of the

. licensee's inspections of the north and south intake bays of the river screen house (RSH) and Nuclear Station Procedure (NSP) WC-3008, " Foreign Material Exclusion," Revision ' Observations and Findinas On August 19,1999, operators secured the 08 CW makeup pump after identifying that the pump's motor running current was much lower than expected. During the subsequent inspection of the pump's suction, the licensee identified that approximately 20 feet of rubber hose had become entangled in the first stage. The licensee removed the hose and retumed the pump to service. The hose apparently had been attached to the pump's oil cooler blow down valve, OCW187B, and had been used to blow down the pump's suction straine The inspectors were initially concemed that inadequate FME controls at the RSH could also potentially affect the operability of the safety-related essential service water (SX)

system makeup pumps and addressed their concem with the licensee. The licensee performed a walkdown of the RSH and identified several potential areas where controls were inadequate to prevent the intrusion of foreign materials into the intake bay These areas included access ladders, floor openings, and a 3 foot by 12 foot floor grating behind the traveling screens. As a result, the licensee initiated PIF B1999-301 performed an apparent cause evaluation, and developed work requests and action tracking items to fabricate and install suitable FME covers for these areas to prevent

' future problem In addition,' the licensee performed diver inspections of the north and south intake bay Divers recovered numerous pieces of foreign material from each intake bay, most of which were located in the vicinity of the access ladder floor openings. All of the items appeared to have been submerged for an extended period of time because the metal objects were heavily corroded and plastic items were discolored and stiff. No foreign materials were found near the suctions of the two SX makeup pumps. Also, the divers verified that the screen surrounding each SX makeup pump suction was intact and able j to prevent large foreign materials from entering the pump's suctio The inspectors reviewed the licensee's apparent cause evaluation for this event, which concluded that station personnel failed to identify the possibility of foreign material intrusion through the existing floor openings that were installed per original desig There were no FME barriers in place at the openings to preclude foreign material intrusion and although divers had retrieved objects on previous inspections of the intake bays, their inspections primarily focused on silt accumulation. No prior problems with foreign materials affecting any makeup pump operation had previously been identifie J

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The inspectors reviewed NSP-WC-3008 and noted that the procedure generally I addressed FME controls as part of the maintenance work control process and provided I recovery actions when FME controls were not maintained. With the exception of the I spent fuel pool, the procedure did not address FME controls beyond the maintenance work control process that would apply to normally open areas susceptible to intrusion of foreign materials !ike the RSH, the CW pump house, and the SX ultimate heat sink l basins. In response to the inspectors' questions, the licensee concluded that the immediate corrective actions for this event were narrowly focused on covering identified

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j floor openings at the RSH. The corrective actions did not address the licensee's process for implementing FME controls for normally open areas susceptible to intrusion of foreign materials like the RSH, which led to station personnel's failure to identify the !'

possibility of foreign materialintrusion through the existing floor openings. At the end of this inspection period, the licensee was further evaluating its corrective actions for this issue. No violation of regulatory requirements occurred since the deficiency involved the nonsafety-related CW syste { Conclusions The licensee did not implement effective foreign material exclusion controls at the river screen house, which resulted in the fouling of the first stage of the OB circulating water system makeup pump with a rubber hose in addition, the licensee's corrective actions for this event were narrowly focused and did not address the licensee's process for implementing foreign material exclusion controls for normally r, en areas susceptible to intrusion of foreign materials like the river screen house. No violation of regulatory requirements occurred since the deficiency involved the nonsafety-related circulating water syste Ill. Enaineerina E7 Quality Assurance in Engineering Activities E7.1 Untimely implementation of Corrective Actions for a Failure of an Emeraency Diesel Generator Inspection Scope (37551)

The inspectors evaluated the licensee's implementation of corrective actions for Licensee Event Report (LER) 50-454/98-018, " Inoperable Unit 1 Diesel Generator Due to Low Lube Oil Pressure Condition." The inspectors interviewed operations and engineering department personnel and reviewed the following document .

PIF B1998-03968,"1 A D/G [ Diesel Generator] Trip During Startup Causing Unintentional LCOAR [ Limiting Condition for Operation Action Requirement]

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. Root Cause Report 454-200-98-SCAQ00021, " Inadequate Maintenance Procedure Results in 1 A Diesel Generator Trip on Low Oil Pressure"

. Nuclear Tracking System itern 454-201-98-SCAQ02840-03

- Nuclear Tracking System item 454-220-98-03701

. Action Tracking item 8911

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b. Observations and Findinas On September 12,1998, during a routine monthly surveillance test, the 1 A diesel generator tripped during the first minute of operation due to a low lube oil pressure condition which had been caused by inadequate maintenance practices and 1 inappropriate maintenance procedural guidance. The circumstances surrounding this l event and the licensee's corrective actions were documented in LER 50-454/98-018 and NRC Inspection Report 50-454/455-98020(DRP).

One of the licensee's corrective actions for this event included evaluating the use of one of two parallellube oil strainers at a time to preclude the simultaneous clogging of both lube oil strainers and revising the procedures and drawings necessary to modify the system operation. On November 18 and 19,1998, the licensee successfully completed Special Plant Procedure (SPP)98-097, " Unit 2A Diesel Generator Lubricating Oil System Strainer Alignment Test," which functionally tested single lube oil strainer !

operation on the 2A diesel generator. On November 25,1998, the Plant Operations Review Committee reviewed the results of SPP 98-097 and assigned system engineering the action tc perform a startup of the remaining three diesel generators in the single lube oil strainer alignment and complete the necessary changes to engineering docunants, procedures, and operating logs for single lube oil strainer operation of the emergency diesel generator The inspectors noted that while this action item was originally scheduled to be completed on January 28,1999, engineering management had extended the due date three times. The scheduled due date had been extended until September 16,1999, to allow testing of the diesel generators with the permanent strainer differential pressure modification installed instead of the temporary strainer differential pressure modification and to provide additional time for the completion of the testing on the remaining three diesel generators. The inspectors noted that the performance of the testing was not contingent upon the installation of the permanent strainer differential pressure modification. Also, for each of these extensions the licensee did not provide a basis for why the extension was needed or appropriate in the corrective action program ,

documentatio {

During August 1999, the inspectors determined that system engineering did not have a plan to complete the action item and did not expect to complete the action prior to September 16,1999. Specifically: the test procedures had not been developed; the testing had not been scheduled; and the design change package to revise the plant drawings and procedures had not been initiate In response to the inspectors questions, engineering management acknowledged that insufficient management oversight of this corrective action resulted in the action not l being completed prior to the start of refueling outage B1R09, which began on March 27, '

1999. Following the refueling outage, engineering management placed a higher priority on completion of other modification and corrective maintenance activities on the diesel !'

generators through June 1999. However, system engineering made no subsequent progress towards completion of this corrective action until the inspectors questioned the status of the activity. As a result, the cognizant system engineer developed an action plan with milestone dates to complete the testing and design change package necessary to operate the diesel generators in the single lube oil strainer alignment by November 24,199 l

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l t Conclusions The licensee did not complete one of the corrective actions for Licensee Event Report 50-454/98-018, " Inoperable Unit 1 Diesel Generator Due to Low Lube Oil Pressure Condition,"in a timely manner due to insufficient engineering management oversight of the activity. The corrective action involved evaluating the use of one of two 4 parallel tube oil strainers at a time to preclude the simultaneous clogging of both lube oil strainers and revising the procedures and drawings necessary to modify the system 3 operatio l l

l E7.2 Nuclear Oversicht Stoo Work Order on the Installation of Desian Modifications )

I Inspection Scope (37551)

l On September 3,1999, Nuclear Oversight issued a stop work order on the installation of design modifications due to continuing deficiencies with the implementation of the engineering design modification process. The inspectors interviewed nuclear oversight i and engineering department personnel and evaluated the licensee's response to l Nuclear Oversight's stop work orde l Observations and Findinas On September 3,1999, in response to continuing deficiencies with the implementation of the engineering design modification process, all of which involved nonsafety-related equipment, Nuclear Oversight issued a stop work order on the installation of design modifications. Nuclear Overright required that a root cause evaluation be completed to determine the causes for the programmatic breakdown in the modification process and corrective actions be established to preclude recurrence in order to lift the stop work order. The inspectors noted that the issues which resulted in the stop work order were similar to issues previously identified by the inspectors and documented in NRC Inspection Reports 50-454/455-99002(DRP) and 50-454/455-99008(DRP).

On September 7,1999, the licensee assembled a team to conduct a root cause I evaluation of the problems associated with the modification process, which included: l modification installations not being conducted in accordance with design package i documents; modification testing requirements not being implemented in accordance with I design package requirements; procedure or other configuration management document updates not being timely or correctly implemented; and communication issues associated with the intra-departmentalinterfaces during implementation of the modification process. Also, the licensee implemented interim corrective actions to provide additional controls for the installation of design modifications pending completion of the root cause evaluaticn. These corrective actions included: performing a review of all modification related work packages to assure that the design requirements were properly incorporated; assigning a cognizant engineer for each modification; performing a readiness review to determine if the modification was ready to be installed; verifying that the required modification activities were completed during the modification installation; and engineering management reviewing the completed modification prior to turning over the modification to the operations departmen On September 8,1999, Nuclear Oversight lifted the stop work order on the installation of modifications based upon the interim corrective actions. The inspectors noted that

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- the stop work order had been lifted even though the Nuclear Oversight criteria for lifting the stop work had not been completely satisfied; specifically, the root cause investigation had not been completed and the resultant corrective actions to preclude recurrence had not been established. The inspectors determined that the licensee's interim corrective actions were reasonable. At the end of the inspection period, the licensee's root cause evaluation was in progres Conclusions Nuclear Oversight's evaluation and response to the continuing deficiencies with the implementation of the engineering design modification process was appropriate and adicative of a self-critical oversight organizatio IV, Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R Radioloaical Protection Practices Insoection Scooe (71750)

The inspectors performed walkdowns of the radiologically controlled areas in order to evaluate radiation worker practices, radiological postings, and control of locked high radiation areas. The inspectors also reviewed aspects of the licensee's as-low-as-reasonably-achievable (ALARA) progra Observations and Findinas The inspectors determined that the radiological controlled areas ware properly posted for the existing conditions. Locked high radiation area doors were locked and access to radiologically controlled areas was properly controlled by radiation protection personne j Rope boundaries, swing gates, and signs were properly maintained with one exceptio On August 29,1999, the inspectors identified that a contamination control area boundary in the 1B residual heat removal heat exchanger room was incomplete. The rope boundary had become detached from a wall and had fallen to the floor, in

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response to the inspectors questions, radiological protection personnel promptly corrected the problem. The inspectors concluded that this was an isolated incident which was not indicative of a problem with the licensee's control of contamination control area boundarie The inspectors noted that the licensee established aggressive dose goals for 1999 (240 person rem) and for non-outage activities during this inspection period (1 person rem per month). The licensee achieved a monthly accumulated dose of 812 milli-person rem for August 1999, which was a notable improvement compared to previous non-outage months. The inspectors noted that by establishing goals, planning, and holding personnel accountable for accumulated dose, the licensee had been effective at modifying work practices to achieve the recent dose reductions. Although the licensee

- had not consistently met its dose goals during 1999, notable improvements in dose reduction had been mad )

.

The inspectors reviewed the licensee's ALARA controls for auxiliary building access and for several potentially high dose activities. The inspectors noted that prior to auxiliary building entry, radiation protection personnel briefed personnel on the dose rates in i affected high dose areas, identified areas to avoid, and identified the routes that l

resulted in the lowest dose. The inspectors also noted that for several routine j

potentially high dose activities (e.g., emergence ore coolin j system venting and -

operator shiftly rounds), the licensee had been successful at reducing the accumulated dos Conclusions The inspectors concluded that radiologically controlled areas were properly posted and controlled with one minor exception. The inspectors also concluded that improvements in the licensee's as-low-as-reasonably-achievable controls had resulted in notable reductions in the licensee's accumulated dos P1 Conduct of Emergency Preparedness Activities (71750)

During routine resident inspection activities, observations were conducted in the area of emergency preparedness. No discrepancies were note S1 Conduct of Security and Safeguards Activities (71750)

During routine resident inspection activities, observations were conducted in the area of security and safeguards. No discrepancies were note ;

l F1 Control of Fire Protection Activities (71750) l l

During routine resident inspection activities, observations were conducted in the area of l fire protection. No discrepancies were note V. Manaaement Heetinas l

l X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 16,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie l

15 l l

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i PARTIAL LIST OF PERSONS CONTACTED Licensee i

R. Colgiazier, Regulatory Assurance M. Jurmain,~ Maintenance Manager

. B. Kouba, Engineering Manage .

J. Kramer, Work Control Manager S. Kuczynski, Nuclear Oversight Manager W. Levis, Site Vice President R. Lopriore, Station Manager- . .

D. McDermott, Shift Operations Superinte,1de'1t .

W. McNeill, Radiation Protection Manager ,

K. Moser, Acting Regulatory Assurance Manager

.

M. Rasmussen, Operations Support Manager R. Roton, Nuclear Oversight Assessment Manager R. Sheehan, MIS Manager M. Snow, Operations Manager

- INSPECTION PROCEDURES USED -

IP 37551 - Onsite Engineering IP 61726 - Surveillance Observations IP 62707 - Maintenance Observations

~ IP 71707 - Plant Operations

'IP 71750 - Plant Support Activities IP 93702 - Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened

. 50-454/455-99012-01a - NCV Failure to correctly align the Unit 1 RCMS in the auto makeup mode following a batch addition of boric acid to the RCS 50-454/455-99012-01b NCV Failure to control freeze seal in accordance with the station's out-of-service procedure Closed I 50-454/455-99012-01a NCV Failure to correctly align the Unit 1 RCMS in the auto makeup mode following a batch addition of boric acid to the RCS I

50-454/455-99012-01b - NCV Failure to control freeze seal in accordance with the station's out-of-service procedure

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Discussed 50-454/98-018 LER Inoperable Unit i diesel generator due to low lube oil pressure condition

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- LIST OF ACRONYMS USED

. ALARA As-Low-As-Reasonably-Achievable ASME American Society of Mechanical Engineers BAP Byron Administrative Procedure BMP Byron Mechanical Maintenance Procedure BOA " eron Abnormal Operating Procedure

- BOP' L,on Operating Procedure .

CFR Coce of Federal Regulations CW' Circulating Water-CWPl Common Work Practice instruction DRP Division of Reactor Projects ESFAS Engineered Safety Feature Actuation System

- FME Foreign Material Exclusion LCOAR ' Limiting Condition for Operation Action Requirement LER Licensee Event Report NCV Non-Cited Violation NRC Nuclear Regulatory Commission -

NSP Nuclear Station Procedure PDR Public Document Room PlF - Problem Identification Form RCMS Reactor Coolant Makeup System RCS Reactor Coolant System-RP&C Radiological Protection and Chemistry RSH River S:;reen House -

SPP Special Plant Procedure SX Essential Service Water TS . Technical Specification UFSAR Updated Final Safety Analysis Report

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