IR 05000498/1988043
| ML20207G127 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 08/12/1988 |
| From: | Beach A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20207G108 | List: |
| References | |
| 50-498-88-43, 50-499-88-43, NUDOCS 8808230392 | |
| Download: ML20207G127 (18) | |
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APPENDIX U.S. N"CLEAR REGULATORY COMMISSION A REGION IV NRC Inspection Report: 50-498/88-43 Operating License: NPF-76 50-499/88-43 Construction Permit: CPPR-129 Dockets: 50-498 50-499
' Licensee: Houston Lighting & Power Company (HL&P)
P.O. Box 1700 Houston, Texas 77001 Facility Name: South Texas Project, Units 1 and 2 (STP)
Inspection At: STP, Matagorda County, Texas Inspe.ction Conducted: June 27 through July 1, 1988
. Inspectors: A. B. Beach, Deputy Division Director, RIV G. L. Constable, Section Chief, RIV M.'R. Harper, Data Analyst, AE0D E. J. Holler, Section Chief, RIV r W. C..Seidle, Section Chief, RIV, W. F, Smith, Senior Resident Inspector, RIV E. Tomlinson, Project Engineer, NRR R. R. Tripathi, Reactor Systems Engineer, AE0D
/ /' i Approved: tu kor d A/12/88 Jate'
A. E.' E each, De' uty )1 rector, Division of Reactor Projects Inspection Sunnary Inspection Conducted June 27 through July 1,1988 (Report 50-498/88-43 and)
1M499/88-43 Areas Inspected _: Special, announced inspection to assess licensee performance of startup and testing activities involving Unit 1 prior to proceeding above 50 percent power. Specific areas reviewed included: (1) operations, (2) maintenance and work control, (3) surveillance testing and startup testing, (4) events analysis and reporting, and (5) assurance of quality and management invcivement. No inspection of Unit 2 was conducte Results: Within the areas assessed, the licensee demonstrated a good level of perfonnance with no noted major program weaknesse DR ADOCK 0500 J
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1.0 PURPOSE & SCOPE The Systematic Assessment of Licensee Performance (3 ALP) Report No. 50-498/87-65 on South Texas Project Unit 1 assessed performance during the period from January 1 through December 31, 1987. During the period January 4-8, 1988, an NRC team performed an operational . readiness inspecton of the South Texas Project, Unit 1. On March 22, 1988, Houston
. Lighting & Power Company (HL&P) was issued a full power license for-South Texas Project, Unit 1. Since then, HL&P has been conductiiig testing of the South Texas Project, Unit 1 at power levels up to, and including, 30 percent powe Prior to proceeding above 50 percent power, the NRC requested the licensee to review its operational readiness and perform a self-assessment of its performance during the initial phases of the power ascension test progra On June 22, 1988, HL&P submitted its self evaluation of the South Texas Project, Unit I readiness to proceed above 50 percent powe Subsequent?y, during the week of June 27 thrcugh July 1, 1988, NRC Region IV and NRC Headquarters personnel conducted a parallel assessment of the licensee's performanc This Special Performance Assessment covers the period from March 1988 through June 1988. Although the assessment uses SALP methodology, it is in addition to the SALP process. The assessment period of the next South Texas Project SALP will not be adjusted for this assessment. This Special Performance Assessment reviewed: (1) operations,(2) maintenance and work control, (3) surveillance testing and startup testing, (4) events analysis and reporting, and (5) assurance of quality and mangement involvement. This Special Performance Assessment also includes a review of HL&P's self assessment. Both assessments were discussed at a site meeting with the licensee on July 1, 198 .0 OVERALL EVALUATION Performance in the functional area of operations can be characterized as good, with strong programs in-place to ensure safe operation of the facility. Control room decorum was conducive to safe plant operation in that operational tasks were observed to be conducted in a professional manner. The operators exhibited confidence after having experienced the earl:' phase of plant operations. The NRC assessment team found that the licensee's conclusion to continue the power ascension test program in excess of 50 percent power was adequately founde Performance in the area of maintenance and work control was good in that HL&P appears to have the elements of a strong maintenance program in-plac The licensee has sufficient preventive and corrective action programs in-place and has demonstrated the capability to thoroughly analyze problems, develop effective solutions, and aggressively implement corrective action p
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Performance in the area of surveillance testing and startup testing was very goo Test progrcms were well managed and implemented by a qualified j and adequately manned staff. QA SJrveillance Coverage Was effectively I used, and management attention to surveillance problems was eviden l Peformance in the area of events analysis and reporting shows an improvement over earlier performance by the licensee. Reactor trips and ESF actuations have noticeably decreased. Trends regarding loss of safety system function everits and Technical Specifications violations also have improve Performance in the area of assurance of quality and management involvement was very good. There was evidence that corporate management is frequently and effectively involved in site activitie Procedures for control of activities were adequate and in place. Feedback from quality assurance activities were used to provide critical assessments to management and to improve work activitie Overall, the licensee has demonstrated a good level of performance with no major program weaknesse .0 ASSESSMENT DETAILS 3.1 Operations The primary objective of this portion of the NRC assessment was to confinn that maturity and sensitivity to regulatory requirements were such that the licensee can be expected to operate in a safe, conservative, and orderly manner. In preparation for the assessment, the NRC team studied NRC Inspection Reports 50-498/88-01, 88-C9, and 88-11 to revisit issues raised during operational readiness reviews and operations monitoring inspections conducted during the first quarter of 198 Responses to violations identified in the reports were reviewed for adequacy of corrective actions. During the assessment period on site, the NRC team reviewed several plarit procedures and confirmed that commitments made to improve or correct procedures that may have contributed to some of the earlier problems identified in the inspection reports had in fact been corrected. Licensee Event Reports (LERs) issued since January 1,1988, were also reviewed to familiarize the team with the various problems the licensee encountered during the startup test progra During the assessment period on site, Operations Management, Shift Supervisors, Unit Supervisors, Administrative Unit Supervisors, and Reactor Opeiators were interviewed by the NRC team during all three shifts. An NRC team member attended and monitored one shift briefing for each of the three shifts. Plant tours were conducted by the team to observe radiological work practices and plant equipment condition. Most of the emphasis of the on site assessment was placed on the monitoring of cortrol room activities and clearance office operation .. .
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The NRC team also reviewed issues identified in the licensee's self assessment to verify the validity and depth of that assessment. The NRC team fond that the licensee's self assessment was quite self-critical ia the operations area. Recommendations for correction of deficiencies or ,
for improvements were documented in an action matrix which assigned each -
item to a specific individual for responsibility and correction. As of j June 30, 1988, the team noted that at least 28 of the 52 items had been complete The NRC team noted several strengths in the licensee's performance in the area of operations. Control Room decorum was conducive to safe operation of the facility. Administrative and operational tasks were conducted in a formal, businesslike manner, and a quiet atmosphere was prevalant. The NRC team observed improved operator confidence after the operators experienced the early phase of plant operations and testing. The NRC team f also observed that the operators approached events related to the I technical specifications in a conservative manne ]
An example of a conservative approach was demonstrated on June 27, 1988, when an NRC team member was in the control room. A power excursion occurred from 48 to 50.3 percent when feed heater drains were rerouted to the main condenser because of chemistry problem Control room personnel initially believed that the event may have violated Technical Specification 3.2.1 because the reactor might have been out of the Axial Flux Difference (AFD) target band. Although the power excursion was I greater than anticipated by the reactor operator, the AFD was in the target band. Even though the Technical Specification was not violated, Hl.&P management was promptly involved and directed ten specific corrective actions to prevent a recurrence. These actions included procedure reviews l
and revisions, evaluations of the event, and development of a Technical L Specification 3.2.1 interpretation to assist the operators in the futur The NRC team observed that controls for monitoring plant conditions, system status, and Technical Specifications limiting conditions for operation were in-place and appropriately implemented. Although some problems were identified in earlier NRC inspections, the revised equipment clearcnce order program was found to be clear and straight-forward. The NRC team considered that the procedure requirement to reverify all valves within the boundaries of a tagout when the clearance is released was particularly noteworthy. Also, the locked valve program implemented by the licensee provided an effective method to maintain and audit the status of important valves in the plan Although the NRC team concluded that the licensee's performance in the area of operations was good, seme areas for improvement were noted. The licensee's self asfessment appeared to place a great amount of emphasis on the reduction of field change requests (FCRs). This issue was identified as the most significant area rtquiring improvement for the performance objective of procedural compliance. While it is important to keep the number of FCRs to a practical miniinum, the evaluation did not appear to recognize the importance of the timely correction of deficient alarm
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response procedures. Discussions with operating personnel revealed a lack of confidence that the alarm response procedures would provide the information needed when an alarm tripped. This problem apparently existed mostly in the balance of plant (secondary systems) area. The li ensee's self assessment also identified weaknesses in operator experie:..e in the balance of plant operation. The team expressed concern to licensee management that more priority needs to be assigned to ensuring that the balance.of plant alarm response procedures are corrected rather than emphasizing the need of reducing FCR In addition, the NRC team, after a review of reactor operator logs, observed that the logs need to be more informative in terms of significent alarms experienced, entering and exiting limiting conditions for operation, and noting that a previously identified problem had been corrected. The NRC team also observed that the licensee has implemented a Technical Specification Interpretation Manual. However, the licensee's implementing procedure did not appear to require the manual to be purged of obsolete material as the manual contained material not applicable to the current operations phase. These issues were discussed with licensee managemen Shift briefings were generally informative and appeared adequat However, the team noted that one of the three briefings observed was not particularly detailed, The NRC team noted that the acoustics in the briefing room were poor, making it difficult for the NRC team, and possibly some of the watchstanders, to understand all that was being sai The licensee indicated that plans were fonnulated to correct these problem In summary, the team generally concurred with the licensee's self assessment in terms of the areas requiring improvement, and in HL&P's determination that STP, Unit 1, can safely continue its power ascension test program at power-levels in excess of 50 percent power. The NRC team emphasized the import &nce of increased attention to ensuring the balance of plant alarm response procedures were corrected, and the licensee acknowledged the NRC team's concern in this area.
l 3.2 Maintenance and Work Control i
The objective of this part of the assessment was to review the licensee's self assessment of maintenance / work control for a 10-day period in I April 1988, and to determine if there were any concerns within this area that would impact negatively on safe power ascension above the 50 percent level. Emphasis was placed on evaluating the administrative aspects of the licensee's maintenance / work control program. In evaluating the administrative aspects of the licensee's programs, the NRC team concentrated on the main control board, maintenance work request backlog, preventive maintenance daferrals, and maintenance personnel trainin The NRC team reviewed, in addition to the licensee's self assessment report, the background data associated with self assessment, applicable ,
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plant procedures associated with maintenance / work ccatrol, preventive maintenance, reliability centered maintenance background data, and representative monitoring data. The NRC team also reviewed maintenance work request (MW( schedules and the newly developed 16-week surveillance testing schedule. In addition, the NRC team ir.terviewed cognizant personnel associated with scheduling and conduct of maintenance and with preventive and predictive maintenanc At the time of the self assessnent, there was a backlog of MWRs for the Main Control Board (MCB) in excess of 100. The licensee considered this number to be unacceptable, and subsequently formed a task force to address the MCB backlog of corrective maintenance as well as other items identified during the assessment. The task force was subdivided into a maintenance task group and an annunciator task group. The maintenance task group addressed the backlog of corrective maintenance, including the root cause of maintenance problems on the MCB. As of the NRC team assessment, the maintenance backlog had been reduced to less than 25, which included no safety-related systems / components. The maintenance task group also identified the primary cause of high maintenance requirements to be failure or malfunction of components as they were su'ojected to actual loads for the first time during power ascension; i.e., developed leaks or required adjustment. The licensee expects the incidence of maintenance requirements to reduce significantly as the power level increases. This assessment appeared to be accurate since the number of backlogged MWts for the MCB was reduced and has remained low as power was increased to 50 percen The annunciator task group is responsible for evaluating design problems with the MCB annunciators. At the time of this assessment, this group had identified four specific areas that needed to be addressed. These four areas were: (1) common trouble alarms, (2) alarms that do not conform to the dark board concept, (3) first in alanns that mask subsequent alarms, and (4) nuisance alarms. The annunciator task group identified the problems, proposed solutions for study, and established long range i schedules for completing annunciator actions. It should also be noted that no safety-related alarms were masked, and the other identified
- annunciator problems did not significantly impact control room operation The NRC team also determined that the backlog of MCB corrective maintenance did not include safety-related components, and also did not '
l impact significantly on control room operation The NRC team assessment included a review of the licensee's self assessment and background data pertaining to the MCB, a review of data ,
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pertinent to MCB backlog, and interviews of cognizant personnel associated with correcting identified MCB problems. Based on this evaluation of activities involving the MCB, the hRC team concluded that the licensee has demonstrated the capability to be self critical, as well as the capability to develop and implement corrective actions. The team further concluded that this demonstrated thet (1) plant material condition to support, (2) control of maintenance to optimize, and (3) knowledge of personnel in sepport of safe and reliable plant operation is sufficien I
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7 At the time of the self assessment, the licensee identified in excess of 1500 backlogged MWRs. This number was not reduced at the time of the NRC team assessment. However, in the interim, the licensee had expended considerable effort in determining the cause of the backlog, and in developing and implementing programs to correct identified problems. It should be noted, however, that the backlog does not affect. safety-related systems and components. The licensee had identified several major contributors to the MWR backlog problem. These included: (1)avery aggressi re program of writing MWRs during power ascension, (2) a low threshold for writing MWRs, (3) improper classification of MWRs, and (4) inefficient use of maintenance manpower. The latter item was compounded by such things as maintenance managers not working to schedules developed in the Work Control Center (WCC), some MWRs bypassing the WCC, maintenance shops establishing their own priorities and disregarding WCC priorities, and restricted access for plant maintenance during initial power ascensio To reduce these contributors, the licensee had implemented or had proposed for implementation corrective measures that included: (1) plans to change the threshold for writing MWRs, (2) proposals to reclassify some types of MWRs as operations activities, (3) modifications to the MWR tracking system tc eliminate duplicate tracking, (4) daily meetings with maintenance departments to discuss maintenance requirements and scheduling, (5) new schedules for both surveillance testing and maintenance work, and (6) education of appropriate personnel in the function of the WCC and the importance of following WCC developed schedules. When fully implemented, the above actions should be effective in reducing the MWR backlog to an acceptable level. The backlog reduction will also be aided by a reduction in the number of MWRs written as the number of initial problems with systems / components is reduced with continued power ascension, and by increased plant availability as power ascension is complete While reviewing documents, the NPC team noted what appears to be a weakness in P' ant Procedure OPGP03-ZM-0003, "Maintenance Work Request Program." There is no definite step that directs maintenance personnel to L provide inputs to ensure that the data base is updated when a MWR is l
completed. This may account, in part, for the noted discrepancies between the MWR data base and the actual number of MWR tags in the plant.
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In its self-assessment, the licensee noted that a large percentage of identified preventive maintenance activities (PMs) were being deferre The licensee investigated the cause of these deferrals with the following results. As with MWRs, some PMs were deferred because of restr1ctions on equipment availability during power ascension. Also, the backlog of corrective maintenance items had impacted on full implementation of the PM program. In addition, the licensee had detennined that the total number of PMs may be too high. It should be noted, however, that the number of PM deferrals for safety-related components is minimal, and adequate justification for such dcferrals had been provide l I
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The licensee had implemented or planned to implement a number of actions to correct the problem of PM deferrals. These included (1) establishing a priority for all PMs, (2) scheduling all PMs along with MWRs and surveillances, (3) establishing a separate group to review all PMs for their necessity, and (4) implementing a program lor reliability centered maintenance (RCM). A RCH program, when implemented, will allow the utility to streamline its PM program to concentrate on those equipment and-maintenance activities that will have the greatest potential for improving safety and for reducing forced outages and maintenance costs. At present, the PMs for components are based almost exclusively on vendor recomendation The licensee had also implemented some of the elements of a predictive maintenance program. At the time of the assessment, the program emphasized vibration monitoring of selected components on a periodic basis, and trending of changes in the vibration data in both tabular and graphi: form, as well as producing a sunmary of all equipment that has exceeded a preselected level. This vibration monitoring incorporated state of the art equipment and is used by knowledgeable personnel who have received vendor training on the equipmen The NRC team interviewed the training coordinator and reviewed documents showing the specific training courses for maintenance personnel. There are two levels of training; i.e., apprentice and journeyman. Each levei has a specific academic curriculum with it which must be satisfactorily completed isefore maintenance personnel are considered qualifie In addition, maintenance personnel also received practical, hands-on training in the fiel In the background data for the self assessn.ent, however, the NRC team noted some comments from maintenance personnel regarding the need for better knowledge of plant systems and their functions. Training at the
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time of the assecsment included a generic course on pressurized water I reactor (PWR) familiarization which must be attended by all maintenance personnel. However, plans were being developed for a revised course on PWR familiarization which would emphasize plant maintenance. There were also plans being developed for formal training programs for planners, schedulers, and supervisors associated with maintenance. If implemented, these additional training programs should further enhance an already effective maintenance training program, in summary, the NRC team concluded that the licensee had demonstrated both I
a capability and a willingness to be self critical. This was adequately
! demonstrated by the problems identified by the licensee with the MCB, the MWR program, and the PM program. More importantly, however, the licensee had also demonstrated the capability to thoroughly analyze prorelt..ns, to develop effective solutions to problems, and to aggressively implement the solutions. Based on its assesinent, the team concluded that the licensee's self assessment was accurate and had addressed the significant problems I associated with maintenance / work control. The NRC team further concluded that, based on the licensee's corrective actions, none of the problems
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problems _ identified in the self assessment would affect safe plant operations and should not, therefore, be a restriction on continued power ascensio I 3.3 Surveillance Testing and Startup Testing Several test related functional areas were evaluated during the assessment to determine the licensee's readiness to conduct tests above the 50 percent power level. The functional areas assessed were scheduling, test procedures, overdue tests, startup test program audits, the interface between test groups and operations personnel, and the witnessing of a startup tes In conducting this assessment, particular attention was given to the licensee's recent evaluation of its testing programs which was documented in Appendix 0 to the "Evaluation of STP Readiness to Proceed Above 50 Percent Power" report, issued to the NRC on June 22, 1988. During the assessment, the effort was directed more to discussions with key test personnel, attending test-related meetings, and to the observation of test activities, and less to an in-depth review of test procedures, cor ieted test packages, and other related document Current schedules of significant tests were distributed to key plant personnel during the Plan of the Day (P0D) meeting. This 1/2-hour, well structured meeting is held at 9 a.m., Monday through Friday (and frequently on Saturday). The team attended the June 28 POD meeting in which there was brief discussion of the forthcoming power coefficient determination and load swing tests at the 50 percent power level. About one hour prior to the June 28 POD meeting, the Piant Engineering Department (PED) Manager, responsible for managing the test programs, met with his principal staff to discuss and be briefed on surveillance and startup testing issues. An NRC team member attended the meeting and observed a good exchange of information. The PED Manager brought the more important issues discussed during nis daily staff meeting to the attention of the attendees at the 9 a.m. D00 meeting. This one method of comunication appears to be a very effective and timely way to inform key plant personnel of pending significant tests and the status of significant tests in progres The surveillance test program for Unit 1 involves some 3200 tests. The scheduling and coordination of most of these tests were performed by PED (some of the more frequent tests are handled by Plant Operations). The Surveillance Test Coordinator, PED, and the Surveillance Scheduler, who was assigned to Integrated Planning and Scheduling, generated a daily computer printout of those surveillance tests falling in the grace poriod, i.e., the period between test due date, but before entering a Limiting Condition for Operation Action Statement (referred to as drop dead date).
The Surveillance Scheduler prepared 15-30 test packages daily and hand carried these packages to test coordinators assigned to the disciplines involved. Completed test packages were returned to the Surveillance Scheduler, reviewed for completeness in conjunction with the Surveillance Test Coordinator, entered into the computer regarding status, and then hand carried by the Surveillance Scheduler to the Operational Document
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l Control Center for filing. The scheduling and coordination of the I numerous surveillance tests appeared to be working effectively at the time l of the essessmen The matter of missed surveillance tests, which bad been the subject of several recent Licensee Event Reports, was being given considerable attention by plant management. The Plant Manager, in an office memorandum dated June 14, 1988, 1nitiated a task force of eight individuals to
"attain the required level of performance" in the plant surveillance progra During this assessment, an NRC team member attended a task force meeting. The task force chairman reviewed an 11 point Surveillance Program Task Force Plan of Action that addressed (1) the root cause analysis for missed surveillance tests, (2) visiting other plants to identify good practices, (3) long-term training requirements, (4) review of current program procedures for enhancements, (5) using a task oriented format for the surveillance test data base, (6) reviewing test scheduling software features to identify needed improvements, (7) reviewing the test package handling process to identify potential sources of errors, (8)_' reviewing Units 1 and 2 functional organization, (9) investigating the 3 roper update p(rocedure changeof the data to process base,10)
ensure developing and tracking the scledule for actions task force, and (11) periodically reporting status of actions to managemen It became apparent in discussions with key plant personnel involved with the surveillance testing program, that they were totally committed to achieving "zero defect" with regard to missed surveillance tests. The Task Force Action Plan clearly enforced this commitmen The administrative controls for the initial startup test program were established in Station Procedure 1 PEP 04-ZA-0001, Revision 4, "Initial Startup Test Program Sequence and Administration." Station Procedures 1 PEP 04-ZA-0002, Revision 2, "Qualification and Certification of Initial Startup Test Personnel," and IPEPO4-ZA-0003, Revision 2,
"Documentation of Initial Startup Test Results," provided additional guidelines and instructions in the area of startup testing. The NRC team reviewed several completed startup test packages and found no inconsistencies with the Station Procedures identified abov The NRC team witnessed the Power Coefficient Detennination Test (50 percent power level) controlled by Test Procedure 1 PEP 04-ZY-0017. The test was conducted in a manner consistent with the Station Procedures referenced above. The test director for the witnessed test provided strong and knowledgeable leadership during the pre-test briefing and while the test was being conducted. The strong interface between the test group and operations personnel was very important as the test introduced planned 2 percent reactor power transients for about I hour. Personnel in the control roora during the test conducted themselves in a very professional l
manner and were attentive to all ongoing activiv ,os.
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A representative from quality assurance (QA) surveillance was present l during the entire test. He used an audit type form to document important milestones that he observed such as the completion of the several i
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specified test prerequisite In a later discussion with a QA surveillance representative, the NRC team was informed that QA has observed all startcp tests to date, and will continue to do so through the 50-percent power level platea Some instrumentation problems associated with the data acquisition equipment were experienced prior to starting the test but were quickly resolved by the test group. Once all test prerequisites were met, the test went very smoothl The administrative structure and discussions of responsibility for implementation and control of the plant surveillance program were covered in Station Procedure OPGP03-ZE-0004, Revision 7, "Plant Surveillance Program." Station Procedure OPGP03-ZE-0005, Revision 9, "Plant Surveillance Procedure Preparation," provides instructions for the preparation and revision of piant surveillance procedures. Station Procedure OPGP03-ZA-0055, "Plant Surveillance Scheduling," described the administrative structure and division of responsibilities for the scheduling of periodic Technical Specifications surveillance requirement An NRC team menter reviewed 11 completed surveillance test packages selected at random and found no discrepancies between the documents reviewed and the documented surveillance test progra Several strengths were noted regarding the licensee's performance. The test programs were being managed and implemented by a sufficient number of well qualified personnel. The use of Shift Technical Advisors as test directors provided additional technical strength to the startup test program. The use of P0D meetings as one means of coninunicating the current testing status to key plant personnel appeared to be an effective management tool. The Plant Manager's initiation of the eight-person task force to correct the problem of missed k veillance tests was viewed as an effective means to deal with this issue._ Ihe QA surveillance coverage during all startup tests through the 50 percent power plateau was viewed as effectiv The NRC team did note some minor areas for improvement. The NRC team found there was no administrative control to require that the Operational Document Control Center (ODCC) acknowledge, by some documented means, that they have received completed test packages from PED. This weakness became apparent when the NRC team followed up on the loss of a surveillance test package. Documentation did exist that the completed test had been reviewed and approved. There was no documentation to substantiate that the completed test package had actually been delivered to ODCC. In that the completed test package could not be found, it was necessary to reperform the surveillance test. The clocking in and initialing of the sender's copy of the transmittal form for a completed test package would be one means of correcting this weaknes The NRC team also made some observations regarding the licensee's performance in the surveillance and startup testing area. The Surveillance Scheduler is tasked to provide full time support to the Plant
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Surveillance Coordinator, PED, and plays an important role in assuring that surveillance tests are conducted in a timely manner. However, the surveillance scheduler is not assigned on a full-time basis to the PE In addition, in discussions with PED personnel, the NRC team was informed that a program had not been developed to track surveillance tests required to be conducted following a Unit 1 accident or event, even though it would appear appropriate that a tracking system be developed to track these required tests. The NRC team also found that in-house software is currently being used for the surveillance test tracking system, but there was no users manual in existence for this software program. These observations were discussed with the license In summary, the NRC onsite assessment of the STP, Unit 1, Surveillance and Startup Testing Programs supported the licensee's self assessment finding that, in these test areas, STP, Unit 1, was ready to continue its power ascension in excess of 50 percent of rated powe .4 Events Analysis and Reporting The NRC team's assessment in the events analysis and reporting area included a review of the licensee's program for (1) analysis of root causes of events, (2) submittal of "voluntary" Licensee Event (3) use of lessons learned from otner Reports domestic (LERs) and facilities, and foreign reportability,(4) issue of overdue station problem reports (SPRs), (5) missed NRC commitments, and (6) the analysis and handling of balance-of-plant equipment. The assessment also included discussions with responsible licensee personnel in the specific area reviewed, and review of pertinent documents. Observations and findings of the assessment are described below with reference to relevant licensee activities in each are NUREG-1275, "Operating Experience Feedback: New Plants," recommends that new plants focus attention on the balance-of-plant (80P) systems early in life to prevent transients that can cause reactor scrams and Engineered Safeguard Feature (ESF) actuations. The licensee's self assessment did not address B0P equipment. However, as an exemple of licensee attention to B0P equipment, the May 25 turbine driven steam generator feedwater pump failure was selected. Reports by plant engineering and the ISEG were reviewed, and discussions were held with representatives of both group The root cause identified in the preliminary report by engineering was that the high pressure steam inlet stop valve failed to close because of an inadequate spring fcrce. The preliminary ISEG report recomends a further step to review the stop valve design and feed pump preventive maintenance. A comprehensive final report was expected in Augus Procedures had been upgraded to test operation of the feed pumps prmr to startup (including a turbine trip), and hardware modifications have been made to ensure proper trip operation. Analysis of the failure moo ~e and corrective actions appeared to be thorugh, and the licensee rhowed a determination to prev m. recurrenc r
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NUREG-1275 also recommends that a root cause corrective action program is a necessary factor in achieving good performance. As discussed in the licensee's self assessment, root cause determination had not always been completely effective at STP, Unit 1. Recurring technical specification violations indicated insufficient root cause determination, and repeated ESF actuations (primarily control room HVAC actuations) in the past might also have indicated inadequate root cause analysi The NRC assessment team held discussions with licensee engineering, the Independent Safety Engineering Group (ISEG), and HL&P licensing regarding root cause analysis. Personnel responsible for root cause determination had received additional training developed by ISEG to improve the effectiveness of the licensee's root cause determination. Results of review of events at STP, Unit 1, and other plants were incorporated into training programs or were provided as required reading for operations personne The NRC assessment team noted that the nun.bers of technical specification violations and ESF actuation rates appeared to have improved since initial criticality, and were thus indicative )f a more effective root cause determination. The licensee's self as sessment of root cause analysis was adequate, and showed a willingness to ie self-critical. Therefore, although not conclusive, root cause analysis at STP, Unit I appeared to be improvin SPR files were examined and discussions were held with licensing personnel to assess the handliag of "voluntary" LERs. Four voluntary LEPs had been submitted to the NRC: two in 1987 and two in 1988. The NRC assessment team found that the licensee was submitting voluntary LERs to enhance safety by disseminating information that might be applicable to other plants. However, the NRC assessment team identified two submitted
"voluntary" LERs that the team cusidered NRC required reportable event The first event, leakage in the fittings of the essential cooling water system was considered a significant event by the Office of Nucleae Reactor Regulation (NRR). The second event, improper seal material in the steam generator power operated relief valves (PORVs), might also be construed as a potential safety concern and therefore reportable. The NRC assessment team brought this to the attention of the licensee to ensure even though the events had been reported to the NRC, that the licensee's threshold for reportability was appropriat Although the licensee's self assessment did not address event reportsbility, event reportability was asscssed by examining SPR files,
! 50.72 Reportable Events, LERs, and the SPR tracking system. The SPR
! process involved several reviews for events that may be reportable, including reviews by the Plant Operaticas Review Committee (PORC) and the Nuclear Safety Review Board (NSRB). A correlation was found to exist between 50.72 reports and LERs, even though a few 50.72 reports were lacking because of different rule intecpretations, and the SPR tracking system had some missing information.
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Among management lessons for consideration by new licensees in NUREG-1275 is a recommendation for an operating experience feedback program that combines internal events and relevant events from similar plants. The NRC assessment team noted that the licensee's self assessment did not address lessons learned from other facilities. To assess how STP, Unit 1, is
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using lessons learned, discussions were held with personnel from licensing and plant engineering regarding the use of the Nuclear Plant Reliability Data System (NPRDS), the Westinghouse Owners Group (WOG) reports, NRC and j industry reports, and the startup experience of four other plants. Other
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licensee efforts included having a representative at a Belgian plant for one year, formal contacts with Belgian and French plants, informal contacts for information exchange at other U.S. plants, and beginning a performance trending program by huclear Assurance.
The NRC teain found, at the time of this assessmant, that portions of a t
lessons learned program existed in various parts of the organization. A Plant Reliability Task Force reviewed operating experience and recommended improvements in hardware, procedures, and training. As a result of that review, several changes had been made to prevent recurrent events (such as ESFactuations)andothertransients. Additional hardware modifications
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were planned in response to recommendations by the WOG Trip Reduction &
i f.ssessmentProgram(TRAP).
Another issue reviewed by the NRC team involved overdue SPRs. NUREG-1275 advises new plants to minimize the number of deficiencies and outstanding
. items carried fonvard. The utility received a Notice of Violation from NRC for overdue SPRs in January 1988. The licensee's self assessment was reviewed, and discussions were held with licensing personnel regarding this issue. The licensee's self assessment of overdue SPRs appeared to be adequate. The management attention, additional resources, and revised
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l procedures as a result of the Notice of Violation appeared to have solved the problem. The number of overdue SPRs and the delay time for overd;e reports have decreased significantl The NPC assessment team also reviewed the licensee's performance in meeting NRC commitments. Some Notices of Deviation prior to the assessment period indicated several instances where procedures were not followed closely resulting in failures to satisfy NRC commitments. The NRC team found that corrective actions to the Notices of Deviation included procedure revisions, and letters previously sent to NRC were being reverified for accuracy, including a review by Nuclear Assuranc In addition, a 2-week "look ahead" on NRC cocinitments was being provided daily in the Plan of the Day meetings to ensure that management was aware of upcoming commitment dates.
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Performance comparison to other plants was conducted by review of the I licensee's self assessment and an NRC team assessment of performanc With the data readily available to STP, Unit 1 (NUREG-1275 and AE1D/P604),
the self assessment was adequate, except that loss of safety systam function was not addressed. In the first 8 months since the issunnce of the operating license, STP, Unit 1, had the highest number of loss of l
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safety system events (eight) of currently new PWRs (Vogtle, Harris, Braidwood 1 and 2, Byron 2, Palo Verde 3, and Beaver Valley 2). Use of AE0D/P604 for performance comparison had the disadvantage of using data from 1984 and 1985 because performance of new plants has improved so that the basis of comparison has change In summary, STP, Unit 1, performance during the assessment period appeared to have improved over earlier performance. There had been only one unplanned reactor scram from power. The ESF actuation rate decreased from about three per month before initial criticality to about one per mont The technical specification violation rate decreased from about three per month to about one and seven-tenths per month. Loss of safety system function events showed a similar declin .5 Assurance of Quality and Management Involvement The object of this part of the assessment was to review the licentee's assurance of quality and management involvement. The area assessed included management control, verification, and oversight activities which affect or assure the quality of plant activities, structures, systems, and component The area included management system or systems for centrolling the quality of work performed as well as the quality of verification activities that confirm that the work was performed correctly. This area was not adfressed as a separate area per se in the licensee's self assessment. However, the matters encompassed within this area were addressed collaterally in each of the HL&P assessment area As part of this assessment, the team looked at the HL&P self assessment, various licensee procedures regarding problem reporting, surveillances, audits, and assessments. The team attended a session of the licensee's
"Plan of the Day" (P00) meetir.g and portions of a Plant Operations Review Committee meeting. The team interviewed licensee personnel, principally from the Nuclear Assurance Department. Additionally, the team sampled audit reports, deficiency reports, nonconformance reports, station problem reports, 10 CFR 50.59 reviews, design modification packages and other related licensee document The most recent SALP report for South Texas Project rated the area of Quality Programs and Administrative Controls Affecting Quality as Category 1 for Construction QA Activities and as Category 2 for Operations QA Activities. The SALP noced strengths in licensee management attention and involvement in that management is involved in quality issues on a daily basis and problem areas are promptly addressed. The SALP report did note, however, weaknesses in the implementation of the operations QA/QC program. Since the end of the SALP period, the licensee had received a full power license for South Texas Project, Unit 1 and had progressed to Mode 1 operation at 50 percent power at the time of this assessmen The team assessment indicated that programs were in place regarding the identification and resolution of safety problems at South Texas Projec : .
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i 16 The team's sampling of activities indicated a proper management awareness of, and attention to, problems regarding safety. Procedures for the control of activities were well stated and define The NRC assessment team examined a number of quality assurance audit The team found the audits examined to be performance oriented efforts which identified significant issues. Identified issues were entered in a formalized corrective action program through the initiation of deficiency (
reports. The audits appeared to provide an effective means for appraising management regarding the status of the audited activity and for effecting the correction of deficiencie The NRC assessment team also sampled the licensee's provisions for independent review groups. Groups such as the Plant Operations Review
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Connittee and the Nuclear Safety Review Board provided in depth analysis of the day-to-day activities at STP. In general, the groups appeared to perform more than cursory reviews and to focus their attention on safety significant issue A particular strength noted, regarded management involvement. Management was found to be frequently and effectively involved in site activitie This was evident in the crisp manner in which management conducted the morning P0D meeting, including the scope of the matters covered and the questions asked by senior management present at the meeting. Procedures were in place for highlighting current operational status and problems and for highliohting the status of nonconforming conditions ider.tified in the Station Problem Reporting procedure. Management involvement was also evident from the interviews with middle level managers. Policies regarding quality assurance were understood. Involvement by corporate management was evidenced by the feedback middle level managers had received regarding submitted report The assessment team noted a weakness regarding the Station Problem Reporting procedure at South Texas Project (STP Interdepartmental Procedure IP-1.45Q, Revision 1. dated February 22,1988). Problems identified using the procedure, both significant and less significant, were subject to a full range of technical and managerial review r:garding severity classification, prioritization, problem resolution, and trendin The Station Problem Reporting procedure coexisted, however, with at least nine other problem identification and resolution procedures. These included:
OPGP33-ZM-0003 MaintenanceWorkRequestProgram)
OPCP01-ZA-0012 Chemistry Laboratory QA Program)
OPCP01-ZA-0011 Chemistry Analysis Log Sheets and Reports)
QAP-1.5 (Deficiency Reports)
OPGP03-II-0019 Reporting Industrial Safety Concerns)
050P02-ZS-0024 Security incident Report)
OPGP03-ZR-0004 Radiological Controls Deficiency Reporting)
OPGP03-ZF-0014 Fire Prevention Surveys)
IP-4.1Q (Nonconformance Reports)
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Some of the other problem identification and resolution _ procedures were for station wide use while some were for use within a particular departmen Problems identified using these other procedures did not appear.to receive the same level of management attention as problems of equal significance that were identified using the Station Problem Reporting . procedur The February 10, 1988, NRC report on operational readiness inspection of STP conducted January 4-8, 1988, identified a concern regarding the visibility and evaluation given problems identified using the various problem reporting procedures. The licensee had made char:ges to the various procedures by way of including an advisory in each of the other procedures. The advisory alerted the user of the procedure that the problem identified also should be identified as a station problem report if it met the criteria for a Severity Level I problem as defined in the Station Problem Report proce':re. This was not the concern identified by the assessment-tea J In order to understand the concern raised by the assessment team, one must understand the guidelines regarding the Station Problem Report procedur It appeared the Station Problem Report procedure was intended, at the time-of the assessment at least, to address more significant problems. The Station Problem Report procedure advised that, "It is noted that if the l addressed can be adequatel !
condition level documentbeing(Maintenance Work Request (y handled by issuing a lowerMWR),
l Defic Nonconformance Report (NCR), etc.) a PR is not also required, nor should
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l one be issued in lieu of an MCR, DR, NCR, etc. unless the condition also I meets the criteria for a Severity Level I PR. A PR can be utilized in lieu of a MWR, DR, NCR, etc. by an individual who is not familiar with, or is unaware of how to issue one of the lower level documents." IP-1-45Q, Revision 1, page 32. It was the opinion of the assessrnent team that this arrangement had resulted in two families of identified p oblems. The first, those identified using the Station Prnolem Reporting procedure received a high level of management attention, were extensively reviewed,
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(the licensee estimated that approximately 5 percent of the problems initially classified as Severity Level II problems' were upgraded to Severity Level I problems by the plant w.nauer), were subject to trending,
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and were highlighted during the morning P00 meeting if the completion date for corrective action became overdue. The second, those problems of equal severity to Station Problem Report Severity Level II problems, that were j
identified using "lower level" documer.ts, escaped this management attentio Their classification, analysis, prioritization, and correction were conducted on a department level and were subject to higher management review only when and if they were subject to an audit. An obvious problem with this arrangement was that upper management might mistakenly be led to believe that the problems identified in the Station Problem Reporting l
System are the only problems requiring management attentio Because expanding the scope of the Station Problem Report procedure to cover all station problems might seriously impact on the work load of shift supervisors and the plant manager, it was not clear that such action
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was a proper solution to the problem described above. The licensee pointed out that it had considered the familiarity of plant personnel with the department proolem reporting procedures and the number of problems p, occurring in the transiticn from construction to operations as reasons for i not implementing one system at the time of the assessmen Notwithstanding these ;onsiderations, a system or systems that address all <
" station' problems and provide for balanced management attention should be l
developed. On the ' positive side, licensee awareness of this issue was j evident in the interviews conducted and documents reviewed. This area
, should continue to be monitored during future NR0 inspections.
l l Another concern noted by the assessment team regarded trending of identified problere. Although this issue had been identified in past Quality Assurance audits, a working system to trend problems was still not ;
in p~ lace. The,1*censee had issued a procedure for trending but, to date, !
no report of tre..dng had issued, j A less significant weakness observed regarded the Plant Operations Review .
Cocnittee process. The Committee appears to ask insightful questions and l
- to sebject matters before it to a detailed revie From the assessment l L team's limited review, however, it appeared that the Committee's task l might be helped if the organizations sponsoring the mattert under raview )
used a more polished presentation to brief the committea. That is, a more detailed presentation might optimize the time spent by managers during the meeting, especially regarding "walk in" matters. The concern here in that the comittee may be spending timo to do detailed reviews at the expense of maintaining its ability to look at the broad aspects or big picture of the matter under review.
l Overall, the assessment team identified no shortcomings in the areas of Quality Assurance and Management Involvenent regarding the ability of HL&P to operate South Texas Project in a safe manner.