IR 05000266/1999006
| ML20206K066 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 05/07/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20206K042 | List: |
| References | |
| 50-266-99-06, 50-266-99-6, 50-301-99-06, 50-301-99-6, NUDOCS 9905130062 | |
| Download: ML20206K066 (27) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlil Docket Nos: 50-266;50-301 License Nos: DPR-24; DPR-27 Report No: 50-266/99006(DRP); 50-301/99006(DRP)
Licensee: Wisconsin Electric Power Company Facility: Point Beach Nuclear Plant, Units 1 & 2 Location: 6610 Nuclear Road
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Two Rivers, WI 54241 Dates: February 23 through April 10,1999 Inspectors: F. Brown, Senior Resident inspector P. Louden, Resident inspector P. Simpson, Resident Inspector M. Kunowski, Project Engineer
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Approved by: R. Lanksbury, Chief Reactor Projects Branch 5 Division of Reactor Projects 9905130062 990507 PDR
O ADOCK 05000266 PM I
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EXECUTIVE SUMMARY Point Beach Nuclear Plant, Units 1 & 2 NRC Inspection Report 50-266/99006(DRP); 50-301/99006(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week inspection period by the resident inspector Operations
- The Ur!! 2 ;eactor was made critical in a deliberate and controlled manner on February 26,1999. The pre-job briefing conducted prior to making the reactor critical was conducted weli. The duty shift superintendent (the lead senior reactor operator)
ensured that the control room environment was quiet and restricted access to limit I distractions during this activity. (Section 01.1)
- The Unit 2 turbine generator was paralleled with the electrical distribution grid in a j controlled and deliberate manner on March 7,1999. The Unit 2 operations supervisor (a senior reactor operator) in charge of the evolution displayed strong command and control of the activities. (Section 01.2)
- The conduct of control room activities was not measured and deliberate during the shift immediately prior to paralleling the Unit 2 turbine generator to the electrical distribution grid. Activities were directed in a manner that distracted a control room reactor operator involved with preparation for paralleling the unit to the grid. The duty shift superintendent (the lead senior reactor operator) did not maintain the supervisory role of " big picture" control room oversight. (Section 01.2)
- Operators pulled control rods to increase primary power in response to an unanticipated j cooldown caused by an increase in secondary power. This action was inconsistent with !
plant management's expectation that unanticipated secondary power changes normally I be corrected, if possible, rather than responded to with changes of primary powe (Section 01.3)
- The inspectors noted increases in the noise level and the number of distracting activities being performed in the control room. This declining trend was stopped in the latter stages of the inspection period. (Section 01.4)
- The licensee's corrective action program effectively documented continuing equipment status control problems, including the lack of awareness of reactor operators that some control room computer alarms had been removed from service. The quality verification (quality assurance) organization, the off-site review committee, and senior plant management recognized the need to increase the existing focus on establishing effective corrective actions for long-standing problems in this area. (Section O3.1)
- The licensee initiated required training for all nuclear business unit employees. This training focused on cultural issues associated with recent performance problems at the station. Given the events documented in recent inspection reports, the inspectors considered the training to be innovative and appropriately focused. (Section O3.2)
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During the performance of a turbine-driven auxiliary feedwater pump surveillance test, operators were not adequately prepared to respond to a cooldown in the primary system caused by operation of the pump. The primary system cooldown exceeded a procedurally specified reactor trip criterion. Due to an inadequate turnover, the operators were unaware of the trip criterion and did not trip the unit. A non-cited procedural violation was identified. (Section 04.1)
Maintenance
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The maintenance department recognized declining performance trends in the areas of rework and equipment induced operational challenges. A self-assessment, using personnel from other sites, was performed. The licensee identified the need to improve administrative processes, such as the use of work package procedures. Improvement initiatives were being planned at the conclusion of the inspection period. (Section M1.1)
. The licensee experienced equipment status control problems during surveillance testing for the restart of Unit 2 after the refueling outage. Examples included a case where auxiliary operators (non-licensed) tailed to position a containment spray system valve as i prescribed in a required procedure, and a case where reactor operators mispositioned auxiliary feedwater pump discharge valves following a required surveillance test. Two examples of a non-cited violation for failing to follow Technical Specification-required procedures were documented. (Section M1.2)
- Operators were challenged by condenser steam dump malfunctions during the Unit 2 startup. Condenser steam dump problems had been experienced in prior startups and j shutdowns. Maintenance and engineering personnel had addressed each problem on
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an individual basis until operators and station management requested a more thorough evaluation and effective, comprehensive repairs or modifications. Two modifications were subsequently made to the valves and the valve controllers, and no further problems were experienced. (Section M2.1) l
- The licensee continued to improve their " restart readiness" process to manage and ensure resolution of identified conditions adverse to quality prior to the restart of Unit (Section M6.1)
Encir,eerino
- The inspectors observed the performance of reactor engineering personnel supporting operations staff during the restart of the Unit 2 reactor. Routine reactor engineering tasks were also observed during control room monitoring by the inspectors. The inspectors noted improvement in the performance of reactor engineers during these activities. (Section E4.1)
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Report Details l Summary of Plant Status
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Unit i remained at 100 percent power throughout the inspection period. Unit 2 completed the l Cycle 23 refueling outage and was made critical on February 26,1999. Following low power I physics testing and turbine testing, Unit 2 power was increased to 50 percent. Problems encountered with the Unit 2 "A" steam generator feedwater pump required the unit to remain at 50 percent power while the pump was repaired. Following the repair, Unit 2 power was increased to 100 percent where it remained for the rest of the inspection perio . Operations 01 Conduct of Operations 0 Unit 2 Reactor Startuo ,
l Inspection Scope (71707)
l The inspectors observed the licensee's activities in making the Unit 2 reactor critical on l February 26,1999. The inspectors reviewed the following licensee procedures during i this inspection activity: I
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Operations Procedure (OP) 1 A, " Cold Shutdown to Hot Shutdown," Revision 64,
- OP 1B, " Reactor Startup," Revision 33, and
- Reactor Engineering Surveillance Procedure 4.1, " Initial Criticality and ARO (All Rods Out] Physics Test," Revision 1 I Observations and Findinas The inspectors observed the pre-job briefing conducted on February 26,1999,in preparation for Unit 2 critical-approach activities. The operating supervisor (OS), a senior reactor operator in charge of the evolution, conducted the briefing for all involved personnel. The assistant operations manager was also in attendance. The OS discussed the precautions and limitations contained in the OP 1B procedure and reviewed specific procedural steps for the critical approach. The OS clearly defined roles and responsibilities for each person involved with the startup. In addition, the OS presented lessons-learned and relevant industry operating experience. The assistant operations manager provided a management oversight briefing, which included a discussion of the significance of the evolution to be performed and also a discussion of additionalindustry event Since Unit 2 was to be made critical following a refueling outage, dilution of the reactor cooling system with all control rods out of the fuel core was the method to achieve criticality. During the approach to criticality, the inspectors observed consistent implementation of the licensee's conduct of operations standards for three-way communication, annunciator alarm response, and command and control. The reactor operators (ROs) were attentive to the controls of the plant and conducted actions in a
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deliberate, controlled manner. The ROs used self-checking and peer reviewing techniques frequently throughout the evolutio The duty shift superintendent (DSS), the lead senior reactor operator, ensured that the control room environment was quiet, and restricted control room access to limit distractions to the operators. Reactor engineers provided good support to the operators in monitoring and recommending dilution quantities and assessing the reactor's state after each dilution. The Unit 2 reactor was made critical at 10:33 p.m. on February 26, 199 Conclusions The Unit 2 reactor was made critical in a deliberate and controlled manner on February 26,1999. Tr.p pre-job briefing conducted prior to making the reactor critical was conducted weii. 'ihe duty shift superintendent (the lead senior reactor operator)
ensured that the control room environment was quiet and restricted access to limit distractions during this activity. Reactor engineers provided good support to the operators during the evolutio .2 Unit 2 Turbine Online Activities Inspection Scoce (71707)
The inspectors observed the licensee's activities on March 6 and 7,1999. in preparing for and placing Unit 2 onto the electrical distribution grid. Documents reviewed during this inspection activity included:
- OP 1C, " Low Power Operation to Normal Power Operation," Revision 67, and
- Point Beach Test Procedure (PBTP) 092 " Unit 2 Turbine Generator Startup Following Low Pressure Turbine Retrofit Outage," Revision Observations and Findinas j I
The inspectors observed control room activities in preparing to place the Unit 2 turbine j generator onto the electrical distribution grid. The initial activities observed were during !
the later part of the " swing" shift on March 6,1999. The reactor was at about 7 percent j power and holding for completion of condenser steam dump repairs which had been >
ongoing throughout the da Once condenser steam dump repairs had been accomplished to allow for continuation of starting the turbine, the OS in charge of Unit 2 directed that reactor power be increased to the PBTP 092 procedure prescribed band of from 10 to 17 percent powe t While the power increase was ongoing, the DSS conducted a pre-job briefing of the turbine online activities to be accomplished. The RO performing the Unit 2 power increase was one of the individuals involved in the brief. The briefing was a supplement to the more detailed briefing the operators had received during prior shifts for the y activit Following the completion of the briefing, activities ensued to begin starting the turbin During that time, the inspectors noted that the environment in the control room was very [
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busy with evident pressure to accomplish the turbine startup activities on that shift. The DSS became actively involved with the individual activities of the ROs. On one occasion, the DSS was observed emphasizing to an RO the need to " pick up the pace" in order to complete an activity. These inspector observations indicated that the DSS did not maintain the " big picture" responsibility for that position as described in Operations Manual 1.1, " Conduct of Operation," Revision 2. In addition, the activity level was not measured and deliberate as was typical of other earlier evolutions at Point Beach. Based on these observations, the inspectors concluded that the pace of activities and the role played by the DSS created a distraction to some of the ROs
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involved in the siartup of the turbin The turbine was started and brought to synchronous (1800 revolutions per minute)
speed at 10:30 p.m. The DSS decided that the rest of the turbine startup activities ,
would be turned over to the oncoming midnight shift. The pace of activities became J'
measured and deliberate following this decisio !
The midnight shift crew assumed responsibilities for completing the activities to synchronize the turbine generator to the electrical distribution grid. The inspectors noted a clear change of the control room environment and activity level with the change of operating crews. The OS in charge of the Unit 2 turbine evolution provided clear instructions to the control room ROs and in-plant auxiliary operators (via radio). The l
Unit 2 OS conducted brief discussions regarding expected plant responses prior to j initiating critical phases of the evolution. Based on these observations, the inspectors l concluded that the Unit 2 OS provided strong command and control of the activity. The turbine generator was placed online in a deliberate and controlled manner. All operators involved consistently used three-way communications and adhered to standards for l
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annunciator alarm response. The RO responsible for turbine monitoring provided excellent oversight of an RO in-training who was involved with the evolution. The DSS maintained a " big picture" overview of the control room activities and appropriately j
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addressed the Unit 2 OS's questions. The Unit 2 turbine generator was connected to the electrical distribution grid at 1:33 a.m. on March 7,199 The inspectors provided their observations of the turbine generator synchronization l activities to station management. With regards to the observations of swing shift j activities on March 6,1999, licensee management held a crew meeting to more fully l understand the course of events which occurred that evening prior to allowing the crew :
to assume shift duties. The inspectors considered the licensee's response to the l inspectors' observations to be appropriat j
c. Conclusions
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c The Unit 2 turbine generator was synchronized to the electrical distribution grid in a controlled and deliberate manner on March 7,1999. The Unit 2 operations supervisor (a ;
senior reactor operator) in charge of the evolution displayed strong command and
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control of the activitie I The conduct of control room activities was not measured and deliberate during the shift immediately prior to the Unit 2 turbine generator being synchronized to the electrical J distribution grid. Activities were directed in a manner that distracted a control room operator involved with preparation for paralleling the unit to the grid. The duty shift l
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superintendent (the lead senior reactor operator) did not maintain the supervisory role of
" big picture" control room oversigh .3 Operator Response to Cooldown when Unit 1 Turbine Synchronized to Grid While synchronizing the Unit 1 turbine to the grid on January 25,1999, an unanticipated l cooldown occurred. In response to the primary system temperature reduction, the Unit 1 RO withdrew control rods a total of 8 steps. The Unit 1 OS supported the decision to change primary power in response to the secondary side load change. The unanticipated primary system response was caused when the turbine picked up more i load than normal due to a defect in the turbine limiter. The inspectors discussed the ]
operator response to this minor transient with senior reactor operators (SROs) on the shift, including the Unit 1 OS. The members of the crew indicated that changing primary power was the anticipated response for such minor transients, and that they were j prepared to reduce secondary power if rod withdrawal had not stopped the cooldow I When plant management became aware of the minor transient, during a subsequent morning meeting, the site vice president and plant manager expressed concern that operators had not reduced secondary power back to the existing primary power level in response to the turbine limiter problem. Plant management's expectation was that the initial response to unanticipated secondary side power changes should normally be focused on adjusting secondary power, with primary power changes being made only to the extent required by an inability to adjust secondary power in an appropriate manne The inspectors considered plant management's expectations to be appropriately safety conscious. This issue was documented in Condition Report (CR) 99-0290. Corrective actions included reiterating plant management's expectation to the operating crews, improving procedures, and modifying the turbine limiter .4 Noise Levels and Distractions in the Control Room Notable reductions in noise level and distracting activities in the control room have been documented in Inspection Reports (irs) over the last two years. During the current period, the inspectors noted increesds in the noise level and number of dhtracting activities permitted in the control room. These observations were not isolated to specific crews or plant conditions. In one example, the inspectors were present while two RO and three SRO trainees were in the control room. The inspectors considered the control room to be noisy at a distracting level, and that the trainees were contributing to this condition. The two RO trainees were participating in control room activities associated with their training program. The three SRO trainees were discussing training program related technical issues, but were not involved with control room activities. These discussions could therefore have been completed outside the control room are The inspectors discussed the apparent increase in control room noise and number of distractions with the operators and with plant management. During the latter stages of the inspection period, the inspectors noted that the licensee initiated improvement The inspectors were also informed that the licensee had implemented a program for limiting the number of trainees assigned to any one shif _
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' O2 Operational Status of Facilities and Equipment O2.1 Secondary System Material Condition Problems (71707)
During Unit 2 power ascension, secondary-side equipment problems challenged the control room operators several times. These challenges mainly involved responding to condenser steam dump failures. The inspectors observed the operators' respond to condenser steam dump failures on three separate occasions. The operators took quick actions to effectively stabilize reactor power and reactor coolant system (RCS) l l
temperature for each of the observed valve failure Problems with the secondary-side equipment has presented operational challenges in the past, as discussed in irs 50-266/98021(DRP); 50-301/98021(DRP), and 50-266/98019(DRP); 50-301/98019(DRP). Although not previously documented in irs, condenser steam dump failures had also been a problem in the past. The condenser steam dump problems encountered during the Unit 2 startup illustrated the need for continued management emphasis on improving the material condition of secondary-side system O3 Operations Procedures and Documentation l
03.1 Continuina Problems with Status Control of Eauipment l l Insoection Scone (71707) i The licensee had informed the NRC, at public management meetings held during 1997 and 1998, that the operations department was focused on improvement in the control of equipment status. The inspectors monitored the licensee's corrective action system to identify any negative performance trends of potential safety or regulatory significanc This monitoring included review of the licensee's effectiveness at addressing problems with the control of equipment status, Observations and Findinas Problems with equioment status control were identified during the return of Unit 2 to power following the refueling outage. The licensee identified most of these problem The inspectors observed that the quality verification (quality assurance) organization, the off-site safety renw committee, and senior plant management were all sensitive to this issue. The licensee concluded that these problems indicated that previous corrective actions were not complete or had not been fully successful, and that increased focus and attention by the operations department was required to address the weakness. The operations department was working to address both process and human performance issues. The inspectors considered the licensee's assessment to be accurate. Several examples of status control issues are included in this report for the purpose of tracking and trending documentatio In one example, the inspectors observed one shift of operators place two sets of plant process computer system alarms in an inactive status to eliminate nuisance alarm The status of the alarms was recorded in the unit log and on a special equipment status tracking sheet. Two days later, the inspectors noted that the condition which was causing one of the nuisance alarms was no longer in effect, and asked the on-shift crew
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whether the alarm had been re-activated. The operators were not aware that either of the alarms had been inactivated, and they reviewed a different equipment status tracking sheet prior to informing the inspectors that the alarms were still in service. A subsequent computer scan demonstrated that the alarms were still inactive. There was no safety significance associated with either alarm condition, and the unit start-up procedure would have required a computer scan prior to the unit reaching full powe The significance of the observation was that the two operating crews had different understandings of the licensee's controls for removing alarms from service. This had been an area of inspector concern for approximately one year. A new operations department procedure for removing alarms from service was subsequently issued on March 26,1999. Two additional examples of problems with equipment status control are discussed in Section M Conclusions 4 The licensee's corrective action program effectively documented continuing equipment status control problems, including the lack of awareness of reactor operators that some control room computer alarms had been removed from service. The quality verification I (quality assurance) organization, the off-site review committee, and senior plant management recognized the need to increase the existing focus on establishing effective corrective actions for long-standing problems in this are .2 Trainina to Address CulturalIssues Associated with Recent Performance Inspection Report 50-266/99004(DRP) documented recent performance issues at Point Beach. Sections O3.1 and M1.2 document additionalissues. During this period, the licensee initiated two mandatory training programs for all nuclear business unit )
employees. One training session dealt with the cultural issues that led to the freezing i of the safety injection (SI) system common minimum flow line described in ]
IR 50-266/99004(DRP). The inspectors attended one session of this class, and found it to be highly interactive, appropriately focused, and potentially effective. The second training session was more general in nature, and was intended to address the long-term ,
estab'ishment of an enduring safety conscious work ethic at the station. Aspects of the !
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training were intended to specifically address performance problems addressed in IR 50-266/99002(DRP); 50-301/99002(DRP) and this report. The inspectors reviewed ;
the learning aids for this training, and considered them to be innovative and potentially i effective. The inspectors considered the licensee's recognition of the necessity for such ]
training to be indicative of an appropriate awareness of the current challenges at the '
facilit Operator Knowledge and Performance (71707)
0 Inadvertent RCS Temoerature Reduction Durina Turbine-Driven Auxiliary Feedwater (AFW) Pumo Testina i Inspection Scope (61726)
The inspectors reviewed the circumstances surrounding an RCS inadvertent temperature reduction which occurred during testing of the turbine-driven AFW pump on l March 1,1999. The inspectors reviewed the following documents during the course of this inspection activity:
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- OP 1C, " Low Power to Normal Power Operations," Revision 67, and
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IT 09A," Cold Start Testing of the Turbine-Driven Auxiliary Feed Pump and Valve Test Unit 2 (Quarterly)," Revision 1 b. Observations and Findinos The licensee performed the Technical Specification-required testing of the turbine-driven AFW pump and valves for Unit 2 on March 1,1999. The purpose of the test was to verify the cold fast start performance of the turbine-driven AFW pump. The Unit 2 reactor was at 1.5 percent power at the beginning of the test. Two ROs were involved with the conduct of the test and the duty operating supervisor (DOS) was the only SRO in the control ro-om at the tim Shortly after initiating the cold start test of the turbine-driven AFW pump, the Unit 2 RO noted that pressurizer level was decreasing and that the charging system was ,
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increasing flow to compensate for the pressurizer level change. The DOS and one of the ROs also noted that RCS temperature was decreasing rapidly. The DOS had the RO withdraw control rods, and instructed another RO to stop the AFW flow to the "A" l steam generator. The RO withdrew control rods in a controlled manner at three-to-four step intervals over a two and one-half minute period. The second RO stopped the AFW flow and the operators recovered from the temperature transien During the transient, the RCS loop temperatures fell below 540 *F for a period of about l five minutes. Reactor power decreased to 1.2 percent during the initial cooldown, and j then increased to a maximum of 3.6 percent in response to the control rod movemen l Shortly after the transient, the DSS entered the control room and was apprised of what had occurred during the testing. The DSS reviewed the procedures which were in effect at the time. During a review of procedure OP 1C, the DSS identified the following caution statement in the procedure:
"If T,y can not be maintained greater than 540*F, or within 10*F of T,,,, then,
' Trip the reactor Verify Turbine Trip Go to EOP (Emergency Operating Procedure]-0, Reactor trip or safety injection" The lowest RCS temperature the operators observed was 536*F in the "B" RCS cold leg. The DSS, recognizing that the procedural requirements had not been followed, stopped the testing and conducted a control room briefing of the events. Once all personnelinvolved had discussed the occurrence and the requirements of the operating procedure, the operators continued with the turbine-driven AFW pump testing, which was completed satisfactorily without further inciden The plant manager was informed of the occurrence the following morning. He and the operations manager decided to relieve the operators involved with the testing for the remainder of their midnight shift rotation in order to gather facts surrounding the even The initial root cause determination concluded that the operators did not appropriately review the in-progress procedure (OP 1C) during the turnover for the midnight shift;
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therefore, they were unaware of the RCS temperature limit caution and reactor trip requirements contained in the procedure. This caution was located five pages before i the steps in the procedure to which the operators had been working. In addition, the operators did not adequately discuss the effects the turbine-driven AFW pump testing would have on the primary side of the plant, and were not prepared to effectively control RCS temperature once the test started. The licensee also determined that the 540'F trip requirements were not design basis limitations; therefore, the event was not reportable to the NR The inspectors independently verified the plant responses to the event and determined {
that the operators did move control rods in a controlled manner. Likewise, the design basis limitations for accident analyses were determined to be based on an RCS temperature of 530* The operators' failure to trip the reactor when RCS temperature decreased below 540*F as prescribed in procedure OP 1C was determined to be a violation of Technical !
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Specification 15.6.8.1, for failure to operate the plant in accordance with approved procedures. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-301/99006-04(DRP)), consistent with Appendix C of the Enforcement Polic ;
This violation is in the licensee's corrective action program as CR 99-065 t Conclusions During the performance of a turbine-driven auxiliary feedwater pump surveillance test, operators were not adequately prepared to respond to a cooldown in the primary system l caused by operation of the pump. The primary system cooldown exceeded a !
procedurally specified reactor trip criterion. The operators did not trip the plant because ,
they were unaware of the trip criterion due to an inadequate turnover. A non-cited procedural violation was identifie l 08 Miscellaneous Operations issues (92901) l
08.1 (Closed) Unresolved item (URI) 50-266/98019-01(DRP): 50-301/98019-01(DRP):
Licensee procedure adherence guidance. The licensee adopted a procedure adherence philosophy that required procedures to be performed as written or else revised using approved procedure revision processes. Technical Specification (T/S) Change Request 211 was submitted on January 29.1999. The proposed change supports prompt and effective formal procedure changes, eliminating the perceived need to use informal (
procedure changes via the "N/A" and partial procedure performance processe .2 (Closed) Licensee Event Report (LER) 50-266/99002: 50-301/99002: Technical 3 Specification required shutdown of Unit 1 due to potential failure of 4160-volt electrical breakers. This issue was discussed and dispositioned in Section 01.1 of IR {
50-266/99002(DRP); 50-301/99002(DRP), issued March 10,199 '
08.3 (Closed) LER 50-301/99001: Emergency diesel generator output breaker failed to remain closed during surveillance test. This issue was discussed in Section M1.1 of IR 50-266/99002(DRP); 50-301/99002(DRP), issued March 10,1999. After the event, l the licensee concluded that the unanticipated loss of all power to the Unit 2 "A" train electrical bus resulted in the allowed surveillance test exemption of T/S 15.3.1.A.3. not being satisfied. This placed the unit outside of the T/S 15.3.1.A.3.b-allowed 11 i
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I conditions for operable residual heat removal (RHR) systems. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-301/99006-02(DRP)),
consistent with Appendix C of the NRC Enforcement Policy. The licensee's corrective '
action program tracked this issue under the LER number listed herei .4 (Closed) Insoection Follow-uo item (IFI) 50-266/97020-01(DRP): 50-301/97020-01(DRP): Assess control of spent fuel pool operations. Section 01.2 of IR 50-266/97020(DRP); 50-301/97020(DRP) documented the results of several observations ,
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by the inspectors of spent fuel pool activities. The inspectors were concerned about an indicated lack of sensitivity to the importance of maintaining adequate command and control over spent fuel pool activities. The inspectors opened an IFl to track the review of the licensee's corrective actions pending their completion. The inspectors subsequently reviewed the licensee's evaluations and actions taken for CRs 97-3092, 97-3164, 97-3172, and 97-3173. The inspectors concluded that the licensee's actions satisfactorily resolved the concem .5 (Closed) LER 50-266/98029-00: Service water pumps auto start function on emergency diesel generator breaker closure failure. On December 27,1998, the licensee identified ;
that the emergency standby power to both Unit 2 safeguards buses 2A05 and 2A06 was ]
out-of-service, a condition prohibited by T/Ss. The licensee determined that the cause l of the event was the failure to recognize the full significance of de-energizing the Unit 2 '
safeguards relay racks when they were danger tagged out-of-service. The inoperability of emergency standby power to both Unit 2 safeguards buses 2A05 and 2A06 !
constituted a violation of T/S 15.3.7.B.1.f. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-266/99006-03(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation was in the licensee's corrective action program as CR 98-417 II. Maintenance M1 Conduct of Maintenance
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M1.1 Maintenance Deoartment Resoonse to Indications of Performance Problems (62707) l As discussed in IR 50-266/99002(DRP); 50-301/99002(DRP) and in Section O2.1 of this s report, post-maintenance rework and plant material condition problems had become an j i
increasing concern to the inspectors. During this inspection period, the Unit 2 restart was delayed due to required rework of an "A" steam generator feed pump bearin [
Partially in response to the concerns, the licensee initiated an assessment of recent ;
maintenance department performance problems. The assessment team included j personnel from other nuclear facilities. Based on the findings of this team, the i maintenance department manager concluded that significant changes were necessary !
in the application of administrative controls such as the development of, use of, and !
adherence to work packages. At the conclusion of the inspection period, the l maintenance department was developing plans to overhaul their administrative !
processes. This initiative was in addition to the site-wide cultural improvement initiatives i described in Section O3.2 of this report. The inspectors considered the licensee's i recognition of the necessity for tnese improvements to be a strengt j
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M1.2 Eauioment Confiauration Durina Surveillance Testina Insoection Scope (62707)
As discussed in Section O3.1, the inspectors reviewed the effectiveness of the licensee in addressing equipment configuration control problems, as documented in the corrective action program. Two problems related to surveillance testing are discussed below, Observations and Findinas Imoroper Valve Alianment Durina Containment Sorav Surveillance Testina During the performance of activities specified in Inservice Test (IT) procedure 545C,
" Leakage Reduction and Preventive Maintenance Program Test of Containment Spray System When Greater Than 350*F [ degrees Fahrenheit] and not Critical- Unit 2,"
Revision 1, auxiliary operators failed to properly align a valve in the "A" train of the Unit 2 containment spray system, prior to continuing with the "B" train portion of the test. This failure rendered both trains of the containment spray system nonfunctional for approximately three hours until another auxiliary operator discovered the problem. The Unit 2 RCS temperature was 535 degrees Fahrenheit (*F) at the time; therefore, containment spray was not required to be operable by Technical Specifications (T/Ss).
The failure of the auxiliary operators in ensuring the proper valve alignment as prescribed in the IT 545C surveillance test procedure was determined to be an example of a failure to follow procedures in accordance with T/S 15.6.8.1. This Severity LevelIV violation was being treated as a Non-Cited Violation (NCV 50-301/99006-01a(DRP)),
consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 99-064 Imoroper Throttle Position for Auxiliary Feedwater (AFW) Valve l l
During follow-up to questions asked by the NRC Engineering and Technical Support Team inspection (IR 50-266/99005(DRS); 50-301/99005(DRS)), the licensee identified that the Unit 2 turbine-driven AFW pump (2P-29) discharge throttle valves were throttled improperly. The post-test steps of IT 9A," Cold start testing of turbine-driven AFW pump and valve test Unit 2 (Quarterly)," Revision 18, required that valves 2AF-4000 and 2AF-4001 be throttled to produce pump flow consistent with a figure attached to the IT. The figure gave varying pump flows plotted against the steam generator pressure at the time the test was performed. The throttle valve position was considered important to ensure that the AFW pumps did not become air bound following a rupture of the non-missile protected portions of the pump suction line from the condensate storage tanks (operator action is required to transfer pump suction to the safety-related service water (SW)
source after the pumps trip on low suction pressure). The as-left throttle positions for the IT 9A surveillance test performed on February 27,1999, were not consistent with the figure. This failure to perform a required surveillance test as specified in a required procedure was considered to be an additionti example (NCV 50-301/99006-01b(DRP))
of the failure to follow procedures in accordance with T/S 15.6.8.1. The licensee declared all four AFW pumps (effecting both units because of the common suction line)
inoperable when the improper valve setting was identified. The licensee returned the other three AFW pumps to service by tripping the 2P-29 steam supply throttle valv The 2AF-4000 and 2AF-4001 valves were positioned correctly, in accordance with
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IT 9A, prior to the expiration of the 2P-29 T/S allowed outage time. The licensee performed a retrospective review of the impact of the improperly adjusted valves, and concluded that the AFW pumps had not been rendered inoperable by their mispositioning. The inspectors reviewed the analysis and did not identify any basis for differing with the conclusions. This violation was in the licensee's corrective action program as CR 99-0801, 1 I Conclusions )
The licensee experienced equipment status control problems during surveillance testing for the restart of Unit 2 after the refueling outage. Examples included a case where auxiliary operators (non-licensed) failed to position a containment spray system valve as prescribed in a required procedure, and a case where ROs mispositioned AFW pump discharge valves following a required surveillance test. Two examples of a non-cited violation for failing to follow T/S-required procedures were documente M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Condenser Steam Dumo Problems and Repairs (62707)
As discussed in Section 02.1 of this report, operators were frequently challenged during the Unit 2 restart by recurring problems associated with the condenser steam dump l The problems ranged from debris and grime in the pneumatic system to mechanical failures of the condenser steam dump controllers. These problems were initially l
addressed individually, with only limited troubleshooting performed by maintenance and engineering personnel. After several steam dump valve failures, station management l and operators requested that repair activities be more thoroughly evaluated, and that a ]
lasting solution to the steam dump valve problems be developed. The more thorough )
I maintenance and engineering assessment led to modifying the steam dumps to change a component on the controfler and change a previous modification to the valve ste These repairs were effective in preventing further challenges to the operators during the remainder of the startu M6 Maintenance Organization and Administration !
M6.1 Unit 2 Refuelina Outaae Restart Readiness Committee (62707)
The inspectors observed the Unit 2 refueling outage restart readiness committee l
meeting held on February 24,1999. Upper station management attended the meeting with representatives from all station departments.. The meeting included an assessment of corrective action program items, operability determinations, and pending work which had been identified as needing resolution prior to Unit 2 criticality. The inspectors observed that the managers openly discussed outstanding items and reviewed a listing of" restart" items which were considered necessary by the necessary to complete prior :
to Unit 2 reactor criticality. Overall, the inspectors concluded that the licensee continued
. to improve the " restart readiness" process, managing and ensuring the resolution of identified conditions adverse to quality prior to unit restar .
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) LER 50-266/97044-00: 50-301/97044-00: Use of dedicated operators during inservice testing of containment spray system constituted an operation prohibited by T/Ss. On December 16,1997, the licensee identified that activities specified in certain IT procedures required dedicated operators to replace the automatic containment spray additive function. During the previous performances of those test procedure activities, the licensee inappropriately relied on operator action to maintain containment spray system operability when the system was required operable by the T/S. The licensee subsequently revised the IT procedures such that dedicated operators would not be required. The failure to have procedures appropriate to the circumstances constituted a violation of 10 CFR Part 50 Appendix B, Criterion V. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-266/99006-05(DRP); 50-301/99006-05(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 97-380 !
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M8.2 (Closed) LER 50-266/98027-00: 50-301/98027-00: Inadequate T/S surveillance testing of non-essential SW isolation logic. On October 13,1998, the licensee identified that portions of the SW system logic circuits were not being tested monthly in accordance with T/S Table 15.4.1-1, item 44, " Reactor Protection System and Emergency Safety )
Feature Actuation System Logic." The circuits were subsequently tested with satisfactory results. The failure to perform the monthly testing was a violation of T/S 15.4.1, which required the circuits be tested monthly. This Severity Level IV i violation is being treated as a Non-Cited Violation (NCV 50-266/99006-06(DRP);
50-301/99006-06(DRP)), consistent with Appendix C of the NRC Enforcement Polic This violation is in the licensee's corrective action program as LER 266/98-027-0 On October 14,1998, the licensee identified that portions of the SW system logic circuits were not being tested every refueling shutdown in accordance with T/S l Table 15.4.1-2, Item 15, " Service Water System." The circuits were subsequently tested with satisfactory results. The failure to perform the refueling shutdown testing was a i violation of T/S 15.4.1, which required the circuits be tested each refueling shutdow l This Severity Level IV violation is being treated as a Non-Cited Violation (NCV.50-266/99006-07(DRP); 50-301/99006-07(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 266/98-027-0 . Enaineerina E4 Engineering Staff Knowledge and Performance E Reactor Enoineerina Staff Imoroved Performance (37551)
The inspectors observed the performance of reactor engineering personnel supporting operations staff during the restart of the Unit 2 reactor. Routine reactor engineering tasks were also observed during control room monitoring by the inspectors. The inspectors noted improvement in the performance of reactor engineers during these activities. The improvement areas were evidenced by crisp, concise contributions during pre-job briefings; clearly defining or describing the activity to be performed and the roles of ear.h worker involved; and strict adherence to the operations department conduct of operations communications standard. The inspectors determined that these
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observed improvements were the product of efforts taken to address previous reactor engineering performance concerns discussed in the cover letter for IR 50-266/98003(DRP); 50-301/98003(DRP).
E8 Miscellaneous Engineering issues (92903)
E The Severity Level IV violations listed below were issued in Notices of Violation prior to I the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because these violations would have been treated as NCVs in accordance with Appendix C, they are being closed out in this repor (Closed) Violation (VIO) 50-266/97017-02(DRP): 50-301/97017-02(DRP): Component Cooling Water (CCW) pump cross-connect valves not tested. This violation is in the licensee's corrective action program as IR 97-01 I (Closed) VIO 50-266/97017-01(DRP): 50-301/97017-01(DRP): Inaccurate information provided regarding CCW cross-connect capability. This violation is in the licensee's corrective action program as IR 97-01 LQlosed) VIO 50-266/97016-01(DRP): 10 CFR 50, Appendix B, Criterion XVI,
. " Corrective Action." This violation is in the licensee's corrective action program as IR 97-01 '
(Closed) VIO 50-301/97016-02(DRP): Technical Specifications violations due to RHR loop inoperability. This violation is in the licensee's corrective action program as IR 97-01 (Closed) VIO 50-266/97016-04(DRP): 50-301/97016-04(DRP): Failure to include l acceptance criteria within IT and maintenance surveillance procedures. This violation is in the licensee's corrective action program as IR 97-01 (Closed) VIO 50-266/97020-05(DRP): 50-301/97020-05(DRP): Failure to conform to NUREG-0737. This violation is in the licensee's corrective action program as IR 97-02 (Closed) VIO 50-301/97020-06(DRP): Failure to submit an LER. This violation is in the licensee's corrective action program as CR 97-304 (Closed) VIO 50-266/97021-02(DRP): 50-301/9-(021-02(DRP): Containment hatch interlock inoperability. This violation is in the licensee's corrective action program as IR 97-02 (Closed) VIO 50-266/97021-04(DRP): 50-301/97021-04(DRP): Inadequate testing of CCW system. This violation is in the licensee's corrective action program as IR 97-02 (Closed) VIO 50-266/97021-05(DRP): 50-301/97021-05(DRP): Inadequate operability determination for CCW system. This violation is in the licensee's corrective action program as IR 97-02 *
(Closed) VIO 50 266/98003-02a.b(DRP): 50-301/98003-02a.b(DRP): Inadequate thermal power procedure. This violation is in the licensee's corrective action program as IR 98-00 (Closed) VIO 50-301/98003-03(DRP): Operating permit procedure violation. This violation is in the licensee's corrective action program as IR 98-00 (Closed) VIO 50-266/98006-01(DRP): Failure to follow the procedure regarding reactor operator observations of the main control panels. This violation is in the licensee's corrective action program as IR 98-00 (Closed) VIO 50-266/98006-02(DRP): Failure to follow the procedure regarding the weighing of the reactor vesselintemals lifting rig. This violation is in the licensee's 1 corrective action program as IR 98-00 (Closed) VIO 50-266/98009-04(DRP): 50-301/98009-04(DRP): Failure to test all required refueling systems. This violation is in the licensee's corrective action program as IR 98-00 E8.2 (Closed) IFl 50-266/98011-03(DRP): 50-301/98011-03(DRP): Licensee to submit T/S j change request to address SW model error. The licensee submitted to the NRC on ]
July 30,1998, via letter "NPL 98-0613" requested changes to the T/S related to the SW 4 model erro E8.3 (Closed) IFl 50-266/98006-06(DRP): 50-301/98006-06(DRP): Follow-up of design basis il changes to ensure proper documentation and interdepartmental communication j Section E1.3 of IR 50-266/98006(DRP); 50-301/98006(DRP) documented an instance of ;
lack of communication among the licensee's various rebaselining initiatives which resulted in information not being shared amongst the different departments performing the rebaselining work. The inspectors questioned whether that was an isolated instance or was indicative of a broad problem. In response, the inspectors monitored the licensee's performance for any further rebaselining initiative related miscommunication ,
The inspectors concluded no generic problem existed based on the lack of repeat l events during the period of time monitore l E ;losed) LER 50-266/98015-00 and 01: Containment fan cooler test results outside )
icceptance criteria. The inspectors reviewed the documentation associated with this i issue and considered the docketed information to be accurate and complete. The corrective actions were considered to be appropriat E8.5 (Closed) LER 50-266/98023-00: 50-301/98023-00: Circulating water pumphouse )
roof not in accordance with plant design basis. This event was discussed in j IR 50-266/98017(DRP); 50-301/98017(DRP) Section E1.1. The failure to properly check the adequacy of the design constituted a violation of 10 CFR Part 50, Appendix B,
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Criterion Ill, " Design Control." This Severity Level IV violation is being treated as a Non- i Cited Violation (NCV 50-266/99006-08(DRP); 50-301/99006-08(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 98-280 .
E8.6 (Closed) LER 50-266/98016-00: 50-301/98016-00: Refueling system interlock testing inadequate. This event was discussed and dispositioned in IR 50-266/98009(DRP);
50-301/98009(DRP), Section E4.1. No new issues were revealed by the LE E8.7 (Closed) LER 50-266/98025-00: 50-301/98025-00: Control room ventilation system outside design basis. On July 31,1998, the licensee identified that operation of the control room smoke exhaust fan (W-13C) could prevent maintaining a positive pressure in the control room. That condition was outside the design basis of the control room ventilation system, which required positive pressure in the control room under certain accident conditions to maintain control room habitability from a radiological perspectiv The licensee determined the cause to be an oversight in the initial W-13C modification j project. The failure to maintain the design basis of the control room ventilation system l constituted a violation of 10 CFR Part 50, Appendix B, Criterion til," Design Control." l This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-266/99006-09(DRP); 50-301/99006-09(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 266/98-025-00. The licensee placed a temporary information tag on the W-13C control panel to prevent its operation except for its design purpose of smoke remova The inspectors were unable to identify any open actions in the licensee's corrective action program associated with permanently resolving the reportable condition or eliminating the temporary information tag. The failure to have any open corrective action document to resolve a condition previously identified as being adverse to quality constituted a violation of 10 CFR Part 50 Appendix B, Criterion XVI, " Corrective Action."
This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-266/99006-10(DRP); 50-301/99006-10(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 99-099 j E8.8 (Closed) LER 50-266/98026-00: 50-301/98026-00: Boron dilution analysis did not address all water flow paths; boron dilution alarm not appropriately controlled. On September 14,1998, the licensee identified that operation of the " Potential Dilution in Progress" alarm was not controlled in accordance with the intent of T/S Table 15.4.1-2, item 32. The licensee also discovered the safety analysis for the inadvertent bcron dilution accident did not address that the reactor makeup water pumps could deliver l water through an idle charging pump. The inspectors concluded the actions taken by the licensee sufficiently addressed the event reported in the LER and that this event did not constitute a violation of NRC requirement E8.9 (Closed) Escalated Enforcement item (EEI) 50-266/97022-02(DRP): 50-301/97022-02(DRP): Inadequately rated electrical buses could disable switchgear and cause secondary fires. This issue was originally reported by the licensee in LER 50-266/97-032; 50-301/97-032 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (Enforcement Actions (EAs)97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 50-266/97-032. The primary corrective action was to make modifications or other design provisions to ensure that the affected switchgear (located in six rooms) were capable of interrupting the postulated fault currents that may be generated during 10 CFR Part 50, Appendix R fire scenario In support of this action, the licensee completed a new fault duty calculation (N97-0154, Revision 0, dated December 2,1997). In late March 1999, the licensee's contractor,
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Sargent & Lundy, completed an evaluation of the new calculation and proposed several solutions. From the results of this evaluation, the licensee was developing a project work plan which would include performance of additional evaluations and calculations with new software, along with verification of all design inputs. The project work plan was scheduled to be presented to senior plant management at the end of September 199 Development of the final modification plan was scheduled for late October 199 i E8.10 (Closed) eel 50-266/97022-09(DRP): 50-301/97022-09(DRP): Technical Specification violation of operability requirement for main steamline isolation. The issue was ;
originally reported by the licensee in LER 50-266/97-026; 50-301/97-026 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-026-0 l The primary corrective action was to revise several procedures to sosure that the low reactor coolant average temperature input into the main steamline isolation logic remained operable from cold shutdown until the full rcstoration of the temperature signals during hot shutdown. According to the licensee's tracking system, the procedures were revised on June 13,1997. During the current inspection, the inspectors reviewed one of those procedures, ilCP [ Instrumentation & Control l Procedure) 10.001, Revision 3, " Engineered Safety Features System and AMSAC i System Bypass," and verified that it had been revised appropriately to preclude a repeat of the original failure to meet the operability requiremen E8.11 (Closed) eel 50-266/97022-10(DRP): 50-301/97022-10(DRP): Pressurizer level l controlled higher than assumed in accident analyses. This issue was originally reported .
by the licensee in LER 50-266/97-025; 50-301/97-025 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-025-0 l The primary corrective action was to revise three reactor operating procedures to l remove the steps that allowed a pressurizer level higher than assumed in accident . l analyses. During the current inspection, the inspectors reviewed the three procedures l and verified that they had been appropriately revise l E8.12 [ Closed) eel 50-266/97022-11(DRP): 50-301/97022-11(DRP): Potential SI failure during filling of Si accumulator. This issue was originally reported by the licensee in j LER 50-266/97-009; 50-301/97-009 and was included by the NRC with 23 other 1 problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 j and 97-505). The licensee entered the issue in its corrective action program with a l
tracking number of CR 97-051 i l
The primary corrective action was to modify Operating Instruction 01-100, " Adjusting St Accumulator Level and Pressure," to prescribe the use of only the train " A" Si pump for ,
accumulator filling evolutions. Because of the SI system configuration, the use of this
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pump did not affect the operability of the train "B" SI system, whereas the use of the ;
train "B" pump would render the "A" train inoperable. During the current inspection, the l inspectors reviewed the procedure (Revision 12, dated January 15,1999) and verified that it had been approprP ../ revise I
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E8.13 (Closed) eel 50-266/97022-15(DRP): 50-301/97022-15(DRP): Non-environmentally qualified material (teflon) in containment batch applications. This issue was originally reported by the licensee in LER 50-266/97-027; 50-301/97-027 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective l action program with a tracking number of LER 266/97-027-0 The primary corrective action was to replace the teflon, used in various valves, in the hatch winda rmats, and as tape for joint sealing, with fully qualified material. The i replacements were compieted in late 1997 for Unit 1 and in early 1999 for Unit I E8.14 (Closed) E@ 50-266/97022-16(DRP): 50-301/97022-16(DRP): Potential for a section of the RHR system to overpressurize in containment during accident conditions. This issue was originally reported by the licensee in LER 50-266/97-018; 50-301/97-018 and I was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-018-0 The piping section involved was isolated by so normally closed RHR inlet isolation valves (RH-700 and RH-701) and was normally water-filled, but was not provided with a pressure relief valve. The primary corrective action for Unit 2 was the drilling of a 3/8-inch hole for overpressurization relief in the RCS side-disc of the 2RH-700 double-disc gate valve. This modification was completed in mid-1997. For Unit 1, a relief valve was temporarily installed between the two valves in September 1997 for overpressure protection until mid-1998, when a 3/8-inch hole was drilled in the RCS-side of the 1RH-700 and 1RH-701 valve disc E8.15 (Closed) eel 50-266/97022-17(DRP): 50-301/97022-17(DRP): Non-seismic ductwork (the steam generator channel head ventilation system) located above safety-related equipment in containment. This issue was originally reported by the licensee in LER 50-266/97-008; 50-301/97-008 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-008-0 In July 1997, the licensee completed a modification of the Unit 2 steam generator channel head ventilation system to address the seismic question. The Unit 1 system was similarly modified in May 199 E8.16 (Closed) eel 50-266/97022-18(DRP): 50-301/97022-18(DRP): Potential refueling cavity l drain failure could affect accident mitigation. This issue was originally reported by the I
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licensee in LER 50-266/97-006; 50-301/97-006 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-006-0 This LER described a licensee-identified condition where a valve for the floor drain (modified in 1983) in the lower refueling cavity could fail and trap up to 46,000 gallons of water which the design basis assumed was available for core cooling in the sump recirculation mode of RHR operation. The initial corrective action for this issue was to revise the emergency operating procedures (EOPs) for Unit 1 and Unit 2, EOP-1.3,
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" Transfer to Containment Sump Recirculation," to ensure that the refueling water storage tank would be drained to a sufficient level (6 percent) to compensate for the water potentially trapped in the cavity. Subsequently, the licensee modified the floor drain to eliminate the single-failure potential of the valv E8.17 (Closed) eel 50-266/97022-20(DRP): 50-301/97022-20(DRP): Component cooling water system outside the design basis of a closed system outside of containment. The licensee identified that the CCW system could be open to the waste gas (WG)
compressors in that CCW was provided to the compressor seals through nonsafety-related valves, WG-1030A and WG-1032A. This issue was originally reported by the licensee in LER 50-266/97-009; 50-301/97-009 and was included by the NRC with 23 other problems that were dispositioned in an exercise of enforcement discretion (EAs97-347 and 97-505). The licensee entered the issue in its corrective action program with a tracking number of LER 266/97-009-0 The primary corrective action was the modification of the CCW and WG systems to eliminate the use of CCW as seal water and to provide seal water from the reactor makeup water system. This modification was completed in November 1997. In addition to this corrective action, the licensee reviewed other CCW components to determine if there were any that might render the system open. This review identified that the nonsafety-related solenoid valves controlling the safety-related, air-operated CCW surge tank vent valves should be replaced with safety-related valves. This modification was ongoing at the time of the current inspectio IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls (71750)
The inspectors performed routine tours of the radiologically controlled areas of the plan No radiological protection discrepancies were observe V. Manaaement Meetinas l
X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 9,1999. 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 +
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PARTIAL LIST OF PERSONS CONTACTED Licensee J. R. Anderson, Operations Manger R. P. Farrell, Radiation Protection Mange-V. M. Kaminskas, Regulatory Servic' and Licensing Manager D. P. McCloskey, Maintenance Manager i R. G. Mende, Plant Manager C. R. Peterson, Director of Engineering M. E. Reddemann, Site Vice President J. G. Schweitzer, System Engineering Manager l
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B. A. Wetzel, Point Beach Project Manager, NRR i j
l lNSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-301/99006-01a(DRP) NCV Improper valve alignment during containment spray l surveillance testing l 50-301/99006-01b(DRP) NCV improper throttle valve position following surveillance testing 50-301/99006-02(DRP) NCV Unit outside of the T/S-allowed conditions for operable residual heat removal systems
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50-266/99006-03(DRP) NCV Inoperable emergency standby power to both Unit 2 i
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safeguards buses 50-301/99006-04(DRP) NCV Operator's failure to trip the reactor when RCS temperature decreased below 540*F as prescribed in OP1C 50-266/99006-05(DRP) NCV Failure to have procedures appropriate to the 50-301/99006-05(DRP) circumstances 50-266/99006-06(DRP) NCV Failure perform monthly testing 50-301/99006-06(DRP) ,
50-266/99006 07(DRP) NCV Failure to perform refueling shutdown testing 50-301/99006-07(DRP)
50-266/99006-08(DRP) NCV Failure to properly check the adequacy of the design 50-301/99006-08(DRP)
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50-266/99006-09(DRP) NCV Failure to maintain design basis l 50-301/99006-09(DRP)
50-266/99006-10(DRP) NCV Failure to properly track corrective action !
50-301/99006-10(DRP) {
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I Closed l l
50-301/99006-01a(DRP) NCV Improper valve alignment during containment spray l surveillance testing j
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50-301/99006-01b(DRP) NCV improper throttle valve position following surveillance testing
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URI Licensee procedure adherence guidance l 50-266/98019-01(DRP)
50-301/98019-01(DRP)
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l ITEMS OPENED, CLOSED, AND DISCUSSED (cont'd)
Closed 50-266/99002 LER T/S required shutdown of Unit 1 due to potential 50-301/99002 failure of 4160-volt electrical breakers
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50-301/99001 LER Emergency diesel generator output breaker failed to remain closed during surveillance test 50-301/99006-02(DRP) NCV Unit outside of the T/S-allowed for conditions for operable residual heat removal systems 50-266/97020-01(DRP) IFl Assess control of spent fuel pool operations 50-301/97020-01(DRP)
50-266/98029 LER Service water pumps auto start function on EDG breaker closure failure
- 50-266/99006-03(DRP) NCV Inoperable emergency standby power to both Unit 2 safeguards buses 50-301/99006-04(DRP) NCV Operator's failure to trip the reactor when RCS temperature decreased below 540*F as prescribed in OP1C _
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'50-266/97044-00 LER Use of dedicated operators during inservice testing '
50-301/97044-00 of containment spray system constituted an operation prohibited by T/S .
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50-266/99006-05(DRP) NCV Failure to have procedures appropriate to the 50-301/99006-05(DRP) circumstances 50-266/98027-00 LER Inadequate Technical Specification testing of non-50-301/98027-00 essential SW isolation logic 50 266/99006-06(DRP) NCV Failure perform monthly testing )
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50-301/99006-06(DRP)
50-266/99006-07(DRP) NCV Failure to perform refueling shutdown testing 50-301/99006-07(DRP)
50-266/97017-02(DRP) VIO Component cooling water pump cross-connect 50-301/97017-02(DRP) valves not tested 50-266/97017-01(DRP) VIO Inaccurate information provided regarding CCW 50-301/97017-01(DRP) cross-connect capability
,50-266/97016-01(DRP) VIO 10 CFR 50, Appendix B, Criterion XVI, Corrective action
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ITEMS OPENED, CLOSED, AND DISCUSSED (cont'd)
Closed 50-301/97016-02(DRP) VIO Technical Specifications violations due to residual heat removal loop inoperability 50-266/97016-04(DRP) VIO Failure to include acceptance criteria within IT and 50-301/97016-04(DRP) maintenance surveillance procedures 50-266/97020-05(DRP) VIO Failure to conform to NUREG-0737 50-301/97020-05(DRP) .
l 50-301/97020-06(DRP) VIO Failure to submit an LER 50-266/97021-02(DRP) VIO Containment hatch interlock inoperability 50-301/97021-02(DRP) l 50-266/97021-04(DRP) VIO Inadequate testing of CCW system 50-301/97021-04(DRP)
50-266/97021-05(DRP) VIO Inadequate operability determination for CCW 50-301/97021-05(DRP) system 50-266/98003-02a,b(DRP) VIO Inadequate thermal power procedure i 50-301/98003-02a,b(DRP) l 50-301/98003-03(DRP) VIO Operating permit procedure violation l 50-266/98006-01(DRP) VIO Failure to follow the procedure regarding reactor operator observations of the main control panels 50-266/98006-02(DRP) VIO Failure to follow the procedure regarding the weighing of the reactor vessel internals lifting rig 50-266/98009-04(DRP) VIO Failure to test all required refueling systems 50-301/98009-04(DRP)
50-266/98011-03(DRP) IFl Licensee to submit T/S change request to address 50-301/98011-03(DRP) service water model error 50-266/98006-06(DRP) IFl Follow-up of design basis changes to ensure proper 50-301/98006-06(DRP) documentation and interdepartmental communications 50-266/98015-00,01 LER Containment fan cooler test results outside acceptance criteria 50-266/98023-00 LER Circulating water pumphouse roof not in accordance 50-301/98023-00 with plant design basis
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l ITEMS OPENED, CLOSED, AND DISCUSSED (cont'd)
Closed 50-266/99006-08(DRP) NCV Failure to properly check the adequacy of the design 50-301/99006-08(DRP)
50-266/98016-0 LER Refueling system interlock testing inadequate 50-301/98016-00 50-266/98025-00 LER Control room ventilation system outside design basis 50-301/98025-00 50-266/99006-09(DRP) NCV Failure to maintain design basis 50-301/99006-09(DRP)
50-266/99006-10(DRP) NCV Failure to properly track corrective action 50-301/99006-10(DRP)
50-266/98026-00 LER Boron dilution analysis did not address all water flow 50-301/98026-00 paths; boron dilution alarm not appropriately controlled 50-266/97022-02(DRP) eel Inadequately rated electrical buses could disable 50-301/97022-02(DRP) switchgear and cause secondary fires 50-266/97022-09(DRP) eel Technical specification violation of operability 50-301/97022-09(DRP) requirement for main stcamline isolation 50-266/97022-10(DRP) eel Pressurizer level controlled higher than assumed in 50-301/97022-10(DRP) accident analyses '
50-266/97022-11(DRP) eel Potential Si failure during filling of Si accumulator 50-301/97022-11(DRP)
50-266/97022-15(DRP) eel Non-environmentally qualified material (teflon) in 50-301/97022-15(DRP) containment hatch applications 50-266/97022-16(DRP) eel Potential for a section of the RHR system to 50-301/97022-16(DRP) overpressurize in containment during accident Conditions 50-266/97022-17(DRP) eel Non-seismic ductwork (the steam generator 50-301/97022-17(DRP) channelhead ventilation system) located above safety-related equipment in containment 50-266/97022-18(DRP) eel Potential refueling cavity drain failure could affect 50-301/97022-18(DRP) accident mitigation 50-266/97022-20(DRP) eel Component cooling water system outside the design 50-301/97022-20(DRP) basis of a closed system outside of containment
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LIST OF ACRONYMS USED l
CCW Component Cooling Water CFR Code of Federal Regulations
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J CR Condition Report DOS Duty Operating Supervisor DRP Division of Reactor Projects DRS Division of Reactor Safety ,
DSS Duty Shift Superintendent l EA Enforcement Action eel Enforcement Action EOP Emergency Operating Procedure
- F Degrees Fahrenheit IFl Inspection Followup Item IP Inspection Procedure IR Inspection Report IT Inservice Test LER Licensee Event Report NCV Non-Cited Violation OP Operations Procedure OS Operating Supervisor NRC Nuclear Regulatory Commission ,
PBTP Point Beach Test Procedure l RCS Reactor Coolant System l RHR Residual Heat Removal RO Reactor Operator SI Safety injection SRO Senior Reactor Operator i SW Service Water l T/S Technical Specification TDAFP Turbine-Driven Auxiliary Feedwater Pump URI Unresolved item j
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VIO Violation WG Waste Gas
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