IR 05000272/1990081

Integrated Performance Assessment Team Insp 50-272/90-81 & 50-311/90-81 on 900514-25.Weaknesses Noted.Major Areas Inspected:Evaluation of Current Status of Perceived Decline in Performance Identified in Recent SALP Rept

ML18095A337
Person / Time
Site:	Salem
Issue date:	07/03/1990
From:	Beall J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18095A336	List: IR 05000272/1990081 ML18095A335
References
50-272-90-81, 50-311-90-81, NUDOCS 9007110171
Download: ML18095A337 (56)

Text

Docket Nos.:

Report Nos.:

Licensee:

Facility:

Location:

Dates:

Team Manager:

Team Leader:

Inspectors:

Approved By:

90071.10171 F'DI;:

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U.S. NUCLEAR REGULATORY COMMISSION REGION.I 50-272 50-311 50-272/90-81 50-311/90-81 Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, NJ 08038 Salem Nuclear Generating Station Hancocks Bridge, NJ May 14-25, 1990 James Beall, Senior Resident Inspector Beaver Valley Lynn Kolonauski, Project Engineer Technical Support Staff, DRP Elmo Collins, Senior Resident Inspector,Oyster Creek Paul Harmon, Senior Resident Inspector, Sequoyah Stephen Barr, Resident Inspector, Salem Michele Ev~ns, Resident Inspector, Limerick Michael Markley, Resident Inspector, Yankee Rowe Peter Wilson, Resident Inspector, Beaver Valley Kirke Lathrop, Reactor Engineer, RPS lA Glenn Tracy, Reactor Engineer, RPS 2A Hai-Boh Wang, Operations Engineer, NRR James Kaucher, NRC Consultant Beall, Team Manager 7{s/'7C Date.

OVERVIEW SUMMARY An Integrated Performance Assessment Team (IPAT) inspection was conducted to evaluate the current status of a perceived decline in performance identified in the most recent Systematic Assessment of Licensee Performance (SALP) report for Sale The team consisted of two senior resident inspectors, four resident inspectors, two region based inspectors, one headquarters based inspector, one consultant, and a team leader and manage In order to appropriately cover the areas of interest, the team was organized into four inspection groups:

Operations, Surveillance, Engineering and Technical Support, and Safety Assessment and Quality Verificatio Particular emphasis was placed on evaluating the effectiveness of recent initiatives, program changes, corrective actions and management oversigh In the area of Operations, the team was unable to observe licensee performance during power operation or during plant startup since both units remained shut down for the duration of the inspectio The team witnessed certain operational tests, monitored control room activities, and reviewed plant staffing, tagging control and proce-dure qualit The team also assessed the use of procedures, the status of corrective actions and the adequacy of configuration contro Licensee performance in this functional area was assessed as generally satisfactory with operators exhibiting good understand-ing and control of plant activitie Staffing levels, management involvement and safety taggins implementation were considered to be adequat Weaknesses were observed in procedure quality, procedure implementation and Incident Report initiatio In the area of Surveillance, the team supplemented a general review of the surveillance program with a detailed review of one selected key safety system, the emergency diesel generator Licensee performance in this functional area was a~~essed as wea The.conduct of witnessed tests was goo Significant weaknesses were identified in the prosecution of emergency diesel generator testing and licensee review of surveillance test result Significant weaknesses were also identified in corrective action adequacy and in the inservice testing of the boric acid transfer pump The team assessed the licensee 1 s performance in the area of Engineering and Technical Support to be adequat The team found good support provided by the Engineering and Plant Betterment Department but the support provided by system engineers of the Technical Department exhibited weaknes The permanent plant modification process was satisfactory but there appeared to be misuse and lack of management control of the temporary modification proces The team identified three potentially significant technical issues:

inadequate separation of safety related electrical cable, inadequate response to NRC Bulletin 88-04, 11 Potential Safety Related Pump Loss, 11 and installation of a non-code welded patch repair to the ASME Code Class 3 Service Water Syste Licensee performance in the area of Safety Assessment and Quality Verification was found to be wea Notably strong initiatives for design basis reconstitution and integrated response to events were observe However, plant material conditions were found to exhibit substantial weakness despite management-sponsored improvement program Misuse of the station qualified reviewer process was observe Significant weaknesses in corrective action, safety evaluation screening, and management oversight were also identifie.2 BACKGROUND The last Systematic Assessment of Licensee Performance (SALP)

report for Salem (50-272/88-99 and 50-311/88-99, for the period January 1, 1988 to April 30, 1989) recommended th~t NRC conduct an Integrated Performance Assessment Team (IPAT)

i1spection during the current SALP cycl This IPAT assessed licensee performance in the areas of Operations, Surveillance, Engineering and Technical Support, and Safety Assessment and Quality Verificatio The inspection consisted of plant tours, interviews with licensee personnel, observation of plant activities, and selective examination of procedures, records, and document An--important feature of the team was the extensive interaction among team members to arrive at a collective, supportable assessment of licensee performance and identified areas of strength or weaknes The inspection period was planned to be at a time when one or both units was expected to be operating at powe Plant events and schedule changes resulted in the team being on site with both units in outages for the duration of the inspection perio.3 SUMMARY OF RESULTS Conclusions and assessments are provided in the Details for each functional are Presented below is a brief overview with strengths, weaknesses and other observations for each functional are In each case, the specific source Detail(s)

are referenced inside parenthese. OPERATIONS As both Salem Units were in outages, the team was unable to observe licensee performance during power operation or during plant startu Licensee performance in this functional area was assessed as generally satisfactor Strengths Operations personnel exhibited a good understanding and control of ongoing plant activitie (Detail 2.2.2).

Operations Department corrective actions specified in a sampling of Licensee Event Reports were appropriate and either completed or scheduled for completion within a reasonable period of time with completion traced through the licensee's Action Tracking Syste (Detail 2.2.6)

Weaknesses Weaknesses were observed in procedure quality and implementatio (Details 2.2.3 and 2.2.4)

The team noted that Incident Reports were not written for several events which warranted such documentation per NA-AP-00 (Detail 2.2.4)

Observations Operations Department staffing levels were adequate to conduct safe operation Staffing increases for equipment and senior reactor operators were in progres (Detail 2.2.1)

The safety tagging process was adequat A potential weakness was observed in that no administrative require-ments existed for verification of complete system valve lineups after extensive maintenanc The licensee also had no periodic audit requirements to verify the integrity of outstanding tagout (Detail 2.2.5)

Unlabeled valves within the plant configuration could be a potential weaknes (Detail 2.2.7)

1. SURVEILLANCE The team found the conduct of witnessed surveillance tests to be goo Significant weaknesses, however, were identified in the prosecution of the surveillance progra Licensee performance in this functional area was assesssed as wea Strength Overall, surveillance testing was conducted in a controlled and professional manne (Detail 3.2.3)

Weaknesses The licensee 1 s Emergency Diesel Generator (EOG) surveil-lance test procedures did not include verification of TS 4.8.1.1.2.b and TS 4.8.1.1.2. (Detail 3.2.2)

The team identified that certain EOG TS surveillance test procedures did not include acceptance criteri (Detail 3. 2. 2)

The team identified an instance where the licensee determined that substantial EOG surveillance test procedure changes were not Safety Significant Issues (SSis).

The procedures were changed through the Station Qualifier Reviewer (SQR)

process and therefore did not receive SDRC review and approva (Detail 3.2.2)

The team identified several examples of licensee failure to adequately review and implement corrective actions in response to less than satisfactory surveillance test result (Detail 3.2.4)

Inservice testing of the Boric Acid Transfer (BAT) pumps was characterized by the licensee as successfully completed in spite of degrading BAT pump performance beyond the licensing basis limit This issue illustrated basic programmatic weaknesses and was indicativ~ of poor management oversigh (Detail 3.2.5)

Observations The surveillance program described by AP-12, 11Technical Specification Surveillance Program 11 was adequat (Detail 3.2.1)

The lack of technical surveillance procedure reviews during the ongoing Technical Specification surveillance review program was noted as a potential weaknes (Detail 3.2.2)

The surveillance test result trending program could be improved through expansio (Detail 3.2.6)

1. ENGINEERING AND TECHNICAL SUPPORT Based on the sample used in developing an assessment, the team found the quality of engineering and technical support to vary greatly from very good, as provided from the Engineering and Plant Betterment Department, to weak, as provided by the system engineers of the Technical Departmen Problems were identified in the use of temporary modifications and several other specific area Licensee performance in this functional area was assessed as adequat Strengths The design process within Engineering and Plant Betterment was well controlle (Detail 4.2.1)

Reviewed modification packages and drawings affected by the permanent modification process were satisfactor (Detail 4.2.3)

Weaknesses System engineers demonstrated weaknesses in: knowledge of equipment for which they were responsible, an apparent lack of field presence, and in occasi.onal instances of a lack of proper questioning attitude and attention to detai (Detail 4.2.2)

Misuse of the temporary modification (T-MOD) process was indicated by a marked increase in the number of active T-MODs, failure of the Station Operations Review Committee to review active T-MODs since January 1990, and the number of apparently permanent modifications implemented as T-MOD (Detail 4. 2. 4)

The Technical Department did not trend equipment perfor-mance dat (Detail 4.2.5)

The team identified many instances of inadequate cable separation between different safety related electrical cable group The number of deficiencies and areas affected was indicative of a programmatic weakness in separation of safety related cabl (Detail 4.2.6)

The team identified the potential for pump-to-pump inter-action within the residual heat removal syste However, the licensee's response to NRC Bulletin 88-04, "Potential Safety Related Pump Loss, 11 stated that the potential did not exist, and the licensee had no corrective actions in progress or planne (Detail 4.2.7)

The licensee installed a non-code repair to ASME Class 3 service water piping without prior NRC approva (Detail 4.2.8)

Observations The use of a single individual to track and trend deficiencies and event reports without formal procedures was a potential weaknes (Detail 4.2.5)

The licensee's controls for the use of scaffolding in safety related areas were inconsistent and in some respects, insufficient, in spite of an earlier licensee finding in this regar (Detail 4.2.9)

1. SAFETY ASSESSMENT AND QUALITY VERIFICATION The team found the overall plant material condition to exhibit substantial weaknes Licensee initiatives to improve plant material condition and to upgrade weak procedures had not been successful at the time of the inspectio The team identified multiple examples of weakness in management oversight and untimely or ineffective corrective action Licensee performance in this functional area was assessed as wAa Strengths The Quality Assurance (QA) organization reports reviewed were thorough and contained meaningful assessment of licensee performanc (Detail 5.2.4)

The Significant Event Response Team (SERT) was a noteworthy initiativ SERT assessments were generally comprehensive and detaile The Station Manager's recognition of an inadequate SERT report and subsequent initiation of an independent Onsite Safety Review Group investigation was considered a strengt (Detail 5.2.6)

The Configuration Baseline Documentation (CBD)

project was a noteworthy long term initiativ Reviewed CBD reports were found to be of high qualit (Detail 5.2.7)

Weaknesses Overall material condition of plant areas examined was wea The team identified a number of component and general deficiencies which were not previously identified by the license (Detail 5.2.1)

The team identified instances where procedure changes involving safety significant issues were implemented through the Station Qualified Reviewer (SQR) process instead of receiving SORC review and approval in accordance with TS 6.5.1. This practice was indicative of misuse of the latitude provided by the SQR proces (Details 3.2.2 and 5.2.9)

The Station Qualified Reviewer (SQR) process was not implemented in accordance with TS 6.5.3.2.a in that SQR independence was not maintained for several procedure change review (Detail 5.2.3)

A weakness in corrective action implementation was evidenced by the licensee's failure to provide special training, committed to in response to an NRC violation, to all SQR (Detail 5.2.3)

Follow-up of weaknesses identified by QA was not controlled and was delinquent in some case (Detail 5.2.4)

The licensee's use of tracking and trending was inconsis-ten Tracking and trending of plant events and equipment performance was'either ineffective or nonexisten (Detail 5.2.5)

The Procedure Upgrade Program was an important initiative, but weaknesses in the licensee's prosecution of the program resulted in significant delay (Detail 5.2.8)

The team identified plant and procedure changes that were conducted without required 10 CFR 50.59 safety evaluation Extensive misunderstanding of the requirements of 10 CFR 50.59 was identifie (Detail 5.2.9)

Excessive overtime was routinely worked without prior approval or with an improper level of approval contrary to Technical Specification requirement (Detail 5.2.10) OPERATIONS SCOPE

Examples of ineffective or untimely corrective actions were identifie These included the Nuclear Instrumentation cabinet doors (Detail 5.2.1), special SQR training (Detail 5.2.3), electrical cable separation (Detail 4.2.6), and the Procedures Upgrade Program (Detail 5.2.8).

Observations The material improvement program and the periodic station management tours were good initiatives, but the Salem facility exhibited material deficiencies despite these program (Detail 5.2.2)

The Action Tracking System (ATS) provided an adequate means of tracking open items and commitment closure, but did not track items by priorit This made it difficult to assess the safety significance of overdue item (Detail 5.2.5)

The team reviewed and assessed the conduct of plant operations in the areas of staffing, control of plant activities, adequacy and use of procedures, documentation of deficient conditions, safety tagging, corrective actions, and configuration contro.2 FINDINGS 2.2.l Operations Department Staffing The team reviewed the Operations Department organization and staffing, including the management staff and on-shift personne The team noted that the operations management staff had recently been increased in size and that other efforts to increase manning were either completed or in progres The team viewed this as a positive effor Licensee efforts were also underway to increase the number of senior licensed operators assigned to each shif Field Nuclear Shift Supervisors (NSS) were in training; the licensee intended to use these individuals to provide additional direction and control of in-plant activitie The team also noted that equipment operator staffing had recently been increased and that plans to continue the increase were in plac The team concluded that the staffing levels of Operations Department managers and plant operators were adequate to support safe facility operatio Further, management was committed to continue with the staffing level increases for senior licensed operators and equipment operator.2.2 Control of Plant Activities The team reviewed and assessed operator control of plant activitie This review included observation of control room activities including shift turnover, review of the administra-tive systems to remove and return equipment from service, review of supervision and authorization of activities, and an assessment of plant operator knowledge and understanding of ongoing activitie The team reviewed the surveillance test requirements to estab-lish and verify the Technical Specification (TS) required boration flowpath These surveillance tests included SP(O)

4.1.2.l(B), SP(O) 4.1.2.l(A) and SP(O) 4.1.2.?(A).

The most recent completion of the boration flowpath valve lineup was performed on April 29, 199 It was noted, however, that maintenance activities conducted on May 7 and May 8, 1990, defeated this boration flowpath by closing and tagging ~alves in the syste While the position of tagged valves was verified after completion of these activities, the TS complete surveil-lance valve lineup was not reperforme The team concluded that the site administrative procedures did return the system valves to their required position and that the boration flowpath was returned to servic The team observed, however, that there were no formal requirements to perform system valve lineups after extensive maintenance activities, including the use of any group tagou In practice, valve lineups were performed based on the judgement and decisions 0f either the Senior Nuclear Shift Supervisor (SNSS) or the Operations Enginee The team considered this method to be a potential weakness in the performance of valve lineups after maintenance and tagging activities and, ultimately, to be a weakness in equipment status contro 1.

The team reviewed the mechanisms and documentation used to transfer information from one shift to the nex The team observed shift turnover activities and observed that the operators had a good understanding of the current Technical Specification action statements, and an adequate preshift briefing was conducted by the unit NS The team concluded that control room operators effectively transferred information during the shift turnover proces The team found that shift supervisors were generally cognizant of plant status and ongoing activitie Effective measures were in place for the SNSS to authorize and track maintenance activi-tie Effective information systems were in place for plant operators and supervisors to track equipment tagged out of

service and refer to the status of off-normal equipmen The SNSS effectively authorized and controlled surveillance test The SNSS demonstrated a good understanding of currently installed temporary modification Additionally, the team noted that emphasis was placed on the supervision of plant activities, as demonstrated by a thorough briefing given prior to the performance of a special tes During observations of routine plant activities, inspectors observed good management involvement and understanding of current issue The team observed that licensee management was adequately involved in the review of plant mode change prepara-tion The team reviewed the chemical specification requirements for steam generators during wet layup conditions, including sampling of the steam generators and any corrective actions initiated as a result of out of specification condition No unacceptable conditions were identifie Overall, good control of plant activities, with proper authori-zation and supervision, was observe Operations personnel had a good understanding of ongoing plant activitie.2.3 Adequacy of Procedures During inspection activities and observation of control room activities, the team performed a sampling review of the adequacy of the procedures which were being utilize Two minor procedure errors were identified by the tea The first involved the hydrazine limits as specified in Operating Procedure III.9.3.4 and the second involved the absence of two valves (1SJ910 and 1SJ911) on a valve lineup required by surveillance test Sl.OP-ST.SJ-0013(Q).

These procedure errors were promptly corrected by the license Additionally, the team observed that recently issued surveillance test Sl.OP-ST.SJ-0013(Q), a product of the Procedures Upgrade Program (PUP),

required a number of revisions and temporary change The PUP is discussed in Detail 5. Based on these observations, the team concluded that some weakness was exhibited in the area of procedure qualit.2.4 Use of Procedures During observation of plant activities, plant tours, program reviews and document reviews, the team evaluated the use of procedures, knowledge of procedural adherence* requirements, and the effectiveness of the transmission of site goals and philosophies to procedure user The team reviewed Operations Directive (OD)-15 to evaluate programmatic requirements in the area of procedure adherenc Operations procedures were classified as either Category I, II, or III; each category had specific implementing requirements for procedure usag The team concluded that the requirements were appropriat During discussions with control room and plant operating personnel, the team found that the operators were knowledgeable of the programmatic requirements as specified in OD-1 Additionally, the operators expressed commitment to implementing procedures in accordance with these requirement The team also reviewed the 11 Salem Handbook of Standards 11 which specified general compliance standards for use of procedure The team concluded that these standards forwarded good policies on procedure usag Some team observations, however, showed weaknesses in the attitude of personnel toward procedural requirement These observations included the followin An Emergency Operating Procedure (EDP) required tool box inventory was performed and identified missing gasket No corrective action or efforts were initiated to replace or identify the location of the missing gaskets (Detail 3.2.4).

Plant temporary modifications were not reviewed as required by the Station Operations Review Committee ( SORC) ( Deta i 1 4. 2. 4).

An emergency diesel generator surveillance was performed numerous times with instrumentation, identified as being required to demonstrate operability, being out of servic No corrective action was initiated to restore the instru-mentation to service or change the procedure to more accurately define operability requirements (Detail 3.2.4).

Step F of check-off sheet 2-2 of surveillance procedure SP(O) 4.1.2.lB, 11 Reactivity Control System-Boration,

required cycling of valve l-CV-55 to verify operabilit When the surveillance was performed on April 29, 1990, this step was not performed because l-CV-55 was tagged ou A procedure change was not performed even though the procedure could not be performed as writte In addition, some ineffectiveness was observed in implementing the requirements of site administrative procedure NA-AP.ZZ-006, 11 Incident Reports.

Specifically, boric acid transfer pump

surveillance test failures on February 7 and May 9, 1990, were not documented in incident reports as required by the procedur Also, safety tagging errors were not documented in an incident repor Thes~ examples demonstrated a degree of weakness in the commitment of site personnel to strictly implement procedural requirement.2.5 Safety Tagging The safety tagging program was evaluated to assess its effec-tiveness in controlling system status and ensuring the proper isolation of equipment from energy source Findings are detailed belo The team determined that the safety tagging implementing procedure, NA-AP-ZZ-015, provided clear and precise direction for the preparation, application and removal of safety tag Group tagouts were used to eliminate duplicate tagging for a situation where a number of jobs were to be worked on a given system or componen The group tagout could not be cleared until all of the affected work groups had signed off on the release authorizatio As discussed earlier in Detail 2.2.2, aside from components listed on the tagout, there was no programmatic requirement to perform a status check (e.g., valve lineup) on components inside the tag boundary after the tags were cleare While post-maintenance functional testing would in many cases identify a mispositioned comprnent, the potential existed for a system to be declared operable based on the most recent valve lineup surveillance when post maintenance testing was not performe Reperforming a valve lineup surveillance upon completion of work would alleviate this concern; however, Operations personnel indicated that lineup verifications would often not be reperformed if the previous surveillance was still curren NA-AP-ZZ-015 did not require periodic audits to verify the integrity of outstanding tagout Such audits could provide a measure of the effectiveness of tagging controls on station systems and provide data for trending tagging errors or viola-tion The licensee stated that an audit was usually performed after a refueling outage, although this activity was not proceduralized and audit results were not always documente In summary, the safety tagging process appeared to provide adequate control of system status and personnel protectio Potential weaknesses were noted in the lack of status verifi-cation for all system components following a system 1 s return to service and in the lack of periodic tagout audit.2.6 Operations Department Corrective Actions Approximately twenty Licensee Event Reports (LERs) dealing primarily with operations-related events were reviewed and found to be of generally good qualit Four LERs (50-272/89-029, 50-272/89-035, 50-272/89-037 and 50-311/90-007) were evaluated for adequacy of corrective action In each case, the Opera-tions Department corrective actions proposed appeared appro-priate to address the root cause (or causes) of the event and had either been completed as stated in the LER or were scheduled for completion within a reasonable period of tim Responsi-bility for completion was assigned and entered into the action tracking system (ATS).

The team identified two instances in other areas, however, in which LER corrective actions were incomplete (Detail 5.2.3) or not timely (Detail 4.2.9).

2.2.7 Configuration Control During plant tours, the team evaluated plant conditions for conformance to the required configuratio In one case, the team observed that while an instrument test block was installed, no gauge was present on the service water supplied to the No. 11 charging pump room coole The licensee initiated a work request and replaced the gauge during the inspectio In other instances, the team observed installed plant valves without valve identification number Examples included:

an emergency diesel generator bearing drain valve; several examples of packing lubrication valves installed on air operated valves; and, drain valves connected to the operating hydraulics of th main steam isolation valves (MSIVs).

In each case, the licensee provided documentation that identi-fied these valves as part of the plant configuratio In the case of MSIV drain valves, the licensee evaluated the need for a cap to prevent inadvertent draining of the hydraulics and determined that a cap should be installe The team concluded that unlabeled valves within the plant configuration could be a potential weaknes During performance of charging pump surveillance Sl.OP-ST.SJ-0013(Q), the team noted that several temporary transmitters were installe The team reviewed the documentation and control of the activities which installed and removed these transmitters and no concerns were identifie.3 CONCLUSIONS Operations department staffing was adequate to support safe operation of the facility, with staffing increases planned or in progres In general, the control room operators, plant operators and shift supervisors demonstrated good knowledge and control of ongoing plant activitie Operations and site management involvement was observed in routine plant activitie Some weaknesses were observed in the implementation of procedural requirements and the quality of proce-dure Potential weakness was noted in the areas of valve lineup performance after major maintenance activities, group tagouts, and in the reperformance of technical specification surveillance valve lineup.

SURVEILLANCE SCOPE The team reviewed the Technical Specification (TS) surveillance program, implementing procedures, and selected surveillance results in assessing the licensee 1 s execution and control of the surveillance progra A detailed review of the adequacy of surveillance require-ments associated with one selected key safety system, the emergency diesel generators, was also conducte The team also evaluated the implementation of corrective actions related to the surveillance progra.2 FINDINGS 3.2.1 Technical Specification Surveillance Program Salem Administrative Procedure (AP) 12, 11 Technical Specification Surveillance Program, 11 underwent major revisions in November 1989 as corrective action in response to a number of missed TS surveillances from 1987 to August 198 The revisions included:

AP-12 expansion to clarify the responsibilities and duties of all personnel involved in the TS surveillance program; the assignment of a TS Surveillance Coordinator to each department with TS surveillance responsibilities; and the creation of a Technical Specification Administrator within the Technical Department to coordinate station activities associated with the T The positions were established in late 1988, although they were not proceduralized until revised AP-12 was issued in November 198 Additionally, the licensee modified the Managed Maintenance Information System (MMIS) database in December 1988 so that only three individuals would

have the ability to change important surveillance information such as plant operating mode requirements, surveillance frequency, and scheduled completion date These changes appeared to correct the scheduling problems which caused the missed surveillances discussed abov The team concluded that the TS surveillance program described by AP-12 was adequat. Emergency Diesel Generator Surveillance Review Because of the safety significance of the system, the team conducted a line by line review of the Salem Unit 2 emergency diesel generator (EOG) TS surveillance requirements (TS 4.8.1.1.2) to determine whether the requirements were adequately met by the surveillance procedure The team identified the following discrepancie TS 4.8.1.1.2.b, which requires that 11 at least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to one hour, check for and remove accumulated water from the day tanks, 11 was not addressed in the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> EOG surveillance procedures SP(O) 4.8.1.l.2.C.7.A/B/ TS 4.8.1.1.2.c.7 requires that 11 the steady state voltage and frequency shall be maintained at 4160 +/-420 volts and 60

+/-1. 2 hertz during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run 11 but these limitations are not specified in SP(O) 4.8. 1.1.2.C.7.A/B/ Generator frequency was not addressed and voltage, while recorded on the 11 0iesel Generator Hourly Log, 11 was not identified as part of the acceptance criteria for the tes In following these deficiencies, the team noted that the licensee had made several recent attempts to verify that all Salem TS surveillance requirements were accurately represented in the TS surveillance program procedure The initial attempt, completed in January 1989, verified that the individual TS surveillance numbers were addressed in MMIS databas This review, however, did not verify that the procedure identified in the database actually satisfied the specific TS requiremen Following a missed surveillance in June 1989, the next TS surveillance review focused on TS amendments issued between January and June 198 It was only after a surveillance was missed in September 1989 (LER 50-311/89-15) that the licensee committed to perform a line by line TS review against existing surveillance procedure This effort began in October 1989 and was originally scheduled for completion in April 1990, but the licensee extended the completion date to December 199 The licensee also increased staffing for this effort from one to three person The team noted that the current TS surveillance review effort did not include a thorough technical review to assure that the individual surveillance procedures fully satisfy their associ-ated TS surveillance requirement The licensee maintained that a technical review would instead be completed via the Procedures Upgrade Program (PUP) process as committed to in LER 50-272/

90-07, which described a surveillance missed in March 1990 (the PUP program is described in Detail 5.2.8).

The team viewed this approach as a potential weakness, given the surveillance procedure inadequacies identified and the PUP implementation delay The team noted the following additional procedure discrepancie SP(O) 4.8.1.1.2.C.7.A/B/C did not include engine check-out steps (i.e., oil level checks in governor and crankcase) prior to the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run or appropriate restoration steps following the diesel restart test (step 5.3.7).

Also, procedures SP(O)

4.3.2.l.(A)4 and SP(O) 4.8.1.1.2.C.7.A/B/C did not include acceptance criteria section The inclusion of acceptance criteria in TS surveillance procedures is a clear regulatory requirement (10 CFR 50 Appendix B, Criterion V) and, with their absence, it is not clear how the SNSS could have determined that the tests had been satisfactorily completed in order to declare the EDGs operabl The team identified that in November 1986, the diesel generator enduranr.e run and load rejection test were removed from SP(O)

4.3.2.l(A)4, and SP(O) 4.8.1.1.2.C.7.C was written for this testin TS 6.5.1.6.a required that all procedure changes that involve a Safety Significant Issue (SSI) be reviewed by SOR However, the licensee determined that these changes were not safety significant issue It would appear that, based on the safety significance of the diesel generators and the team-identi fied inadequacies within these procedures, the licensee 1 s determination process was inadequate and resulted in an inappropriate SSI determinatio The above deficiencies identified the licensee 1 s failure to (1)

have adequate procedures for ensuring that TS surveillance requirements were met, (2) conduct TS surveillance testing for TS surveillance requirements 4.8.1.1.2.b and 4.8.1.1.2.c.7, and (3) have SORC review and approval for changes which involve safety significant issues as required by TS 6.5.1. (See Details 5.2.3 and 5.2.9 for further discussion of the SQR process.)

3.2.3 Surveillance Testing Observat~ons The team witnessed the conduct of several surveillance test Overall, testing was conducted in a well controlled manner by knowledgeable and proficient personnel with appropriate super-visio Exceptions are discussed belo The team observed conduct of PI/S-CV-2, 11 Charging Pump Flow Test, 11 for charging pumps Nos. 11 and 1 During the perfor-mance of the test on charging pump No. 12, the reactor operator directing the surveillance did not strictly adhere to the procedure; this allowed a second reactor operator to omit data documentation at a specific flow testpoin The team observed that the operators promptly discovered and corrected their mistak As the operators had just reported on shift, the team noted that the error might have been prevented if the Test Coordinator and Shift Supervisor had been present to observe testing at the time the error was mad The team observed conduct of EOG 2A testing, including portions of M-15A, 11 18 Month Diesel Generator Inspection, 11 on May 15, 199 During the test, licensee personnel were unable to complete the steps requiring firing temperature readings for each cylinder because the panel pyrometer was inoperabl The pyrometer had been inoperable sir.ce November 1989, and a work order had been generate The licensee, however, failed to identify the pyrometer inoperability during planning conducted prior to the tes A procedure change was then required to allow the installation of a temperature fluke to obtain firing temperature readings, which were take~ during a subsequent EOG ru Based on the number of adequate surveillances observed, the team assessed these problems as isolated instances of inadequate test control and plannin.2.4 Surveillance Test Results Review The team reviewed the result of numerous surveillance tests to determine whether the test results were adequately reviewed and corrective actions were taken as necessar The significant results of this review are discussed belo The team reviewed the results of SP(0)4.8.l.l.2, 11 Electrical Power Systems-Emergency Diesels, 11 for the Unit 2 11A 11 EOG, performed on May 8, 199 The team noted that several steps on Check Off Sheet (COS) 2 involving cylinder exhaust temperatures had been completed by writing 11 F/I 11 (for failed indicator) in the associated spaces on COS-The team noted that these steps were marked with asterisks and that a note in the procedure stated that steps marked with asterisks were performed to verify EOG operability per TS 3.8. The team questioned operations personnel and the system engineer regarding these procedure steps and was informed that the cylinder exhaust temperatures were not required for the SP(0)4.8.l.1.2 EOG monthly operability tes The temperatures were only required for the 18 month tes However, this deter-mination was not documented and no measures were taken to have the procedure formally change The team also noted that the pyrometer had been inoperable since November 198 Therefore, monthly surveillance SP(0)4.8.l. had been improperly completed since that tim In response to the team's finding, the licensee initiated a change to SP(O)

4.8.1.1.2 on May 16, 199 Because the cylinder exhaust temperatures were not needed in the monthly operability deter-mination, the lic2nsee deleted the asterisks from the associated procedure steps on COS-The team reviewed PI/S-AF-1, 11 Service Water to Auxiliary Feedwater (AFW) Spool Piece Installation Procedure. 11 This procedure was intended to be used under emergency conditions to provide an alternate feed source to the AFW system upon deple-tion or unavailability of the primary sourc The gaskets required by the procedure were identified as having been missing from the tool box utilized by this procedur The operators'

notes indicating this deficiency were clearly writte1 for the surveillances conducted on November 28, 1989, and January 30, 199 A1though the surveillances were reviewed by the shift supervisors, no corrective actions were initiated upon discover During a plant tour, the team found the tool box secured in place but opened and uncontrolle The licensee immediately performed the associated (monthly) inventory surveillance [SC.OP-PM.ZZ-OOOl(Z)] and again noted that the gaskets were not in the tool bo The licensee later stated that the gaskets were sized such that they would not fit in the tool box; the gaskets were instead locked in the hot shutdown panel nearby, but evidently not all operations personnel were aware of their locatio As corrective action, the licensee locked a second set of gaskets through the tool box chain and added a locked tool box verification to the daily equipment operator round The team noted numerous (and in some cases, long standing)

deficiencies in both containments (as discussed in Detail 5.2.1), but the licensee 1 s Unit 1 containment walkthrough team had identified only minimal deficiencies when procedure PI/S-CONT 1, 11 Containment Walkdown 11 was conducted on March 31, 199 Additionally, the licensee's team was comprised of only two operations personnel when PI/S-CONT 1 stated that a multi-discipl in~ry team of five members should be use The licensee conducted a Unit 2 walkthrough in January 1990, with no deficiencies noted by the licensee 1 s surveillance tea The team noted that the No. 11 Boric Acid Transfer (BAT) pump inservice testing (IST) procedure performed on December 10, 1989, contained a miscalculation on the data shee The differential pressure across the pump was incorrectly calculated to be 34.6 psid instead of 99.85 psi The value of 34.6 psid was significantly below the acceptable total discharge head (TOH) required for the BAT pumps per the procedure (99-10 psid).

Nevertheless, the system engineer and the NSS reviewed and accepted the results without corrective actio The team considered this to be an example of inadequate surveillance test result review by the Operations and Engineering staff These observations are indicative of weakness in the licensee 1 s response to and treatment of less than fully satisfactory surveillance test result The team identified further deficiencies in the licensee's treatment of BAT pump surveillance test results as described belo.2.5 Inservice Testing of Boric Acid Transfer Pumps During a review of the Inservice Test (IST) surveillance records in the Unit 2 surveillance file, the team noted that the No. 22 Boric Acid Transfer (BAT) pump had failed the IST and had fallen into the Required Action Range on February 7, 199 Neverthe-less, on February 15, 1990, the responsible system engineer authorized acceptance of the pum The flow rate of the pump at that time was 48 gp Upon questioning, the NSS informed the team that the pump had failed the next IST on May 9, 199 The flow rate of the pump at that time was 49.2 gp Additional details of BAT pump performance history are presented in Attachment In the course of an interview with the system engineer and a review of pump records, the team found no basis for the accep-tance of the No. 22 BAT pump IST conducted on February 7, 199 Additionally, the following significant discrepancies were identifie The system engineer referred the team to a previous memorandum, dated November 21, 1989, regarding an evaluation of the No. 12 BAT pump low flow condition which existed at that time (54 gpm).

This evaluation had no direct correlation to the No. 22 BAT pump conditio The memo was also considered inadequate for the condition of the No. 12 BAT pump at that time in that it did not provide any technical analysis or correlation to design requirement The memo stated that a basis for pump acceptance is that 11 generally BAT pumps have shown pump performance much less than [the] pump curv The system engineer initiated a more detailed evaluation of the No. 12 BAT pump issue on November 25, 198 However, this evaluation was neither submitted to, reviewed by, nor approved by station management prior to its use in the judgement and decision to accept the No. 22 BAT pump IST failure of February 7, 199 Furthermore, this evaluation contained conflicting analysis in that the evaluation initially determined that the pump was unacceptable but nevertheless concluded that the pump was acceptable for continued us After each BAT pump test failure, the system engineer revised the acceptance criteria such that the pump would pas These revisions did not receive a safety evaluatio (Additional examples of this problem are discussed in Detail 5.2.9.)

In this case, the acceptance of the degraded flow performance represented a possible unreviewed safety questio (A limited BAT pump performance history is provided in Attachment 1.)

The required incident and deficiency reports for IST pump test failures were not initiated on numerous occasion The No. 22 BAT pump test baseline of February 15, 1990, which was signed by the system engineer, IST Coordinator, and the Engineering Supervisor, placed the 48 gpm flow rate of the pump significantly below the required action range (54.0 - 61.8 gpm).

However, the pump's IST results were still accepted by the system engineer on that date and the pump was declared operabl Based on a review of the available data (see Attachment 1),

the inspector noted that the BAT pumps in both units were operated in unanalyzed conditions for extended periods of time during plant operatio The licensee did not know design basis flow rates for the pumps, nor the actual applicability of the 75 gpm design flow rate specified in the Salem Updated Final Safety Analysis Report (UFSAR).

The BAT pumps provide a boron injection flow path for reactivity control during normal and off-normal condition They provide Boric Acid Tank recirculation, the transfer of boric acid solution from the batching tank to the BATs, and emergency boratio The baseline data of the BAT pumps in both units had been altered so frequently that the performance trending of the pumps had not been developed in accordance with ASME Section XI requirement In actuality, the performance of the Unit 1 and 2 BAT pumps had degraded significantly over time; Unit 1 BAT pumps were recently overhauled and returned to conditions near the USFAR value of 75 gp The IST Coordinator recommended corrective actions in order to return all BAT pumps to their design flow (assumed to be 75 gpm) in November 198 This recommendation was not accepted by the Unit 2 system enginee Although they were made aware of the problem and the recommendation, cognizant first level supervisory personnel did not take appropriate action to correct this deficienc While the No. 22 BAT pump was determined to be inoperable by the Technical Manager on the evening of May 22, 1990, operators still considered the No. 22 BAT pump to be operable on the morning of May 23, 199 The operating staff declared the No. 22 BAT pump inoperable later that mornin With the exception of one special test conducted for the No. 12 BAT pump on November 25, 1989, as-installed pump curves have not been developed for the BAT pump Such curves would provide a more accurate basis for safety evaluation At the conclusion of the inspection, no 10 CFR 50.59 safety evaluation had been conducted for the degraded condition of the BAT pump The BAT pump issue illustrated a number of significant licensee weaknesses and failure The fact that a single system engineer could authorize repeated acceptance of a monthly TS required surveillance in spite of apparent degrading conditions is indicative of a basic programmatic weakness and a weakness in management oversigh.2.6 Trending of Surveillance Test Results The team also reviewed the licensee 1 s trending program for surveillance test result At the time of the inspection, the licensee had a program for trending IST data for pumps and was developing a trending program for valve The licensee trended vibration and oil sample data for continuously running pumps such as reactor coolant and service water pumps, but did not trend vibration data for Emergency Core Cooling System (ECCS)

pump These omissions would indicate that surveillance test results trending could be improved through expansion of the trended dat This topic is further discussed in Detail 5..3 CONCLUSIONS The team 1s review of the events surrounding the numerous missed surveillance tests, the licensee 1 s corrective actions, and the diesel generator surveillance procedures for Unit 2 indicated that the licensee 1 s initial corrective actions for the TS surveillance program were too narrowly focused and that this area continued to exhibit weaknes With minor exc~otions, testing observed was conducted in a well controlled and professional manne Weakness was also identi-fied in the licensee response to and follow-up of less than fully satisfactory surveillance test result The BAT pump issue demon-strated weaknesses in management oversight and attention to degrading condition.

ENGINEERING AND TECHNICAL SUPPORT SCOPE The engineering and technical support function was shared by two separate organization The Engineering and Plant Betterment (E&PB) Department provided design support, while the Technical Department provided routine plant operations suppor The team examined both organizations to determine the adequacy, depth and effectiveness of technical support for plant operation The team reviewed various engineering programs and practices to assess plant modification and configuration contro.2 FINDINGS 4. Engineering and Plant Betterment The overall design process within E&PB appeared to be well controlled and contained appropriate checks and balance There was an emphasis on nuclear safety as evidenced by discussions with E&PB personnel, upgrading of procedures (Design Bases/

Input, DE-AP.ZZ-0001 2/90; Test Program, DE-AP.ZZ-0012 3/90; Modification Concerns and Resolutions, DE-AP.ZZ-0017 3/90; Configuration Control, DE-AP.ZZ-0033 3/90; Engineering Workbook for Equivalent Replacement, DE-WB.ZZ-0003 3/90) and implementa-tion of new initiatives (Detail 5.2.7).

E&PB was mainly involved in the design process and less involved in daily plant activitie Most E&PB resources were expended on design-related modifications and associated configuration control issue Direct support for plant related problem resolution was provided upon reques The team did note one specific problem in E&PB procedure control in that several procedures [OA-AP.ZZ-0001(0),

OA-AP.ZZ-0002(0)] were missing from Controlled Procedure Manual set 22 The team viewed this as an isolated case, as no additional controlled procedure inadequacies were identified during the inspectio.2.2 System Engineers The station Technical Department provided routine engineering support for plant operations, reporting directly to the General Manger of Salem Operations (GM-SO).

The department consisted of system engineers from the various engineering discipline These individuals provide day-to-day cognizant system respon-sibility as the 11 first response 11 engineering role for plant equipment problem resolution, operability assessment, technical and safety evaluations for temporary modifications, incident assessment and licensee event reporting, and support to the procedure upgrade program (PUP).

The system engineers received plant systems training comparable to that provided to senior reactor operator (SRO) candidate In addition, some system engineers were former NRC-SRO license holder The team selected a sample (7 of 34) of system engineers, including those with responsibility for key safety systems (such as the EOG and AFW), to assess their knowledge of their assigned system(s).

The team identified inconsistent performance by system engineering personne Some individuals demonstrated an adequate level of technical knowledge; others demonstrated inadequate system knowledge of equipment for which they were

responsibl Examples included a system engineer confusing a pump discharge flowpath with the pump recirculation lin Another individual did not know which heat trace temperature indication provided verification of TS operability for his syste Other significant deficiencies were identified in understanding regulatory requirements associated with assigned system Examples included inadequate technical evaluation and in-service testing (IST) of the degraded boric acid transfer pumps (Detail 3.2.5), the inadequate technical evaluation associated with NRC Bulletin 88-04 (Detail 4.2.7), and the evaluation associated with a non-code repair to service water system piping (Detail 4.2.8).

Further, an apparent lack of system engineer field presence was indicated by a general unfamiliarity with outstanding work requests on assigned system Additional team observations which support this concern include a system engineer who was unable to access the radiologically controlled area (RCA) to walk down his system because his whole-body count had expired several months previousl Another individual demonstrated poor familiarity with standard radiological barrier controls (key components of his assigned system were inside a radiologically controlled area).

The dedication of engineers to manage individual systems is often a source of strength for the assurance of system quality and operabilit The team found that system engineers occasionally displayed a lack of a questioning attitude and attention to detail with regard to deficient plant equipment performanc An examrle involved the disposition of Station Deficiency Report (SOR)90-154, which dealt with erosion of the 23SW CFCU motor coole The SOR was dispositioned by filling the eroded areas of the cooler tube sheet with Belzona 11 R 11 metal and then surface coating the tube sheet with bitumastic coal ta The team found that the cooler heat transfer calculation was not referenced during the disposition to determine if the heat transfer characteristics would be changed due to the application of the filler or coatin Additionally, the system engineer justified not performing a 10 CFR 50.59 evaluation for this modification because the CFCU motor coolers were not explicitly described in the UFSA The motor coolers are an integral part of the CFUs, which are described in the UFSAR and are safety relate An additional example of this problem was the failure of a system engineer to recognize and initiate corrective actions in response to degrading BAT pump IST results, as discussed earlier in Detail 3..2.3 Modification Design Process The team reviewed the Salem program for initiating, designing and implementing facility modification The team reviewed several design packages prepared by E&PB to evaluate procedure adequacy and adherence, as well as the technical assessment of the safety impac Specific elements evaluated included design verification, engineering interfaces, modification process control, engineering assurance drawing control, engineering calculations, post-modification testing, modification package closeout and staff trainin The plant modification process was generally initiated by the submittal of an Engineering Work Request (EWR).

The EWR was normally processed by E&PB after initial review and assessment by a system enginee The E&PB Manager of Projects then evaluated the EWR and assigned a cognizant discipline engineer to implement the design process if it was determined that a modification was neede E&PB provided the primary design and configuration control for all plant modifications, including review and approval authorit Team review noted that the design change process procedures (Design Engineering Administrative Procedures, DE-AP series) were clear and detaile The procedures adequately addressed design interface, design process and corrective action process requirements with appropriate levels of review and verification specifie The team reviewed four modification package The level of review, approval and verification were, in all cases, appro-priate for the complexity of the chang There appeared to be satisfactory performance and documentation of cross discipline review Calculations contained in the modification packages were technically correct and performed in accordance with applicable procedure The 11Workbook for Standard Change Package 11 [DE-WB.ZZ-OOOl(Q)], used to control modification package preparation, review and closeout, was sufficiently detailed to control the design process and post-modification testin The team considered control of drawings affected by the modifi-cation process to be goo Controlled drawings were issued with the change posted against the drawin At the completion of the modification and prior to the issue of the final drawing revision, a verified 11 red line 11 drawing was provided to the control room to ensure that Operations had drawings which reflected the actual plant configurati6 E&PB updated opera-tional working drawings prior to startup, and was required by procedure to formally update drawings within 15 days of closure of the design change packag The team found the drawings affected by modifications to be accurate and appropriately reviewed and approved, with one exceptio The team observed that during implementation of Change No. 2SC-2165 for replacement of Unit 2 service water piping, a contractor performing the work used photocopies of 11 Implementing Field Copy 11 drawing Additionally, the contractor was affixing a 11Working Copy 11 stamp on the photo-copies which was a practice not addressed by station procedure One drawing did not have the required preparation and peer review signature The licensee promptly addressed the team concerns and implemented corrective measure The licensee effectively demonstrated configuration contro.2.4 Temporary Modification Process The team selected a sample of fourteen temporary modifications (T-MODs) for revie The team concluded that five of these T-MODs should have been implemented as permanent modification These included (1) jumpering out five fire protection zone gate valve position supervisory alarm circuits, (2) installing a restraint vibration damper on the No. 12 RHR pump motor, (3)

replacing valve VS in the PASS chemical analysis panel with a three-way valve to allow adequate purge flow during calibration, (4) changing the main turbine bearing metal temperature setpoint from lSO F to 210 F, and (5) removing the diesel driven fire pump control circuit weekly test time The team int 0 rviewed engineering personnel to determine why a T-MOD was used to replace valve VS in the PASS chemical analysis pane Based on the discussions, the team concluded that in order to make the change as quickly as possible, the licensee decided that a T-MOD would be implemente The team observed that the use of T-MODs in place of permanent modifications circumvented the detailed engineering design review process and had the potential to weaken plant configuration contro The team reviewed the T-MOD log in the control room and found that T-MOD 90-051, 11 Temporary Use of Electrical Penetration 2-58, 11 was not logged in or out, but was completed on work request 90012515 rhe team also noted that the licensee had to reconstruct the T-MOD log when summary sheets were lost in 19S These observations demonstrated lapses in tracking of T-MODs, which could cause a loss of configuration contro The procedure governing the temporary modification process required SORC review for all active T-MODs every 91 day However, the team found that active temporary modifications had not been reviewed since January 199 The team noted that the number of T-MODs had more than doubled in the last year and totaled more than 100; the increase was due in part to extensive use of Compound 2X in leaking plant component The team found this rate of increase and lack of SORC review indicative of weakness in management control and oversight of the T-MOD proces. Equipment Performance Data Trending The team reviewed the process for controlling, recording, trending and tracking the performance of instruments used to monitor and provide protection for safety-related parameter The licensee used the 11 Instrument Calibration Data Sheet 11 process to translate performance data for instruments to the working group These sheets had the required performance data listed with spaces to record 11 as-found 11 data, 11 as-left 11 data, and bistable performanc While 11 as-found 11 data was recorded on the completed survei 11 ance test data sheets, 11 as-found 11 data was not recorded on the instrument calibration data sheet The team was informed by the Electrical and I&C Maintenance Engineer that technicians were expected to adjust all instruments as close as possible to required performance at the time of calibratio The licensee stated that this method freed technicians from having to evaluate if the instrument is 11 in 11 or 11 out 11 of the tolerance required by the calibration The completed instrument calibration data sheets were signed off by the shop supervisor, and neither the maintenance engineer nor the system engineer were then required to review the dat Consequently, this safety-related data was neither trended nor tracked within the Technical Grou After th~ data was reviewed by the supervisor, it was entered in MMIS and microfilmed for permanent storag The MMIS provided the dates when calibrations and surveillances were performed, but did not include the 11 as-found 11 and 11as-left 11 dat As stated above, the result was that the Technical Department was not trending equipment performance dat The licensee program for tracking and trending deficiencies and event reports was conducted by a single individual in the Technical Departmen Although the team noted good performance on the part of the subject individual, a potential weakness was noted in that these activities were informal in nature and not controlled or maintained by station procedure Another poten-tial weakness was the absence of peer review afforded other station programs designed to promote quality performanc The licensee was in the process of securing the services of a second individual for this functio The team noted that E&PB had established a data base to trend the performance of the Engineered Safety Feature Actuation System (ESFAS), the reactor protection system, and the nuclear instrumentation bistable This program was aimed at providing the necessary statistical data to justify an increase in testing frequencies from one month to four month Tracking and trending are assessed by the team in Detail 5..2.6 Electrical Cable Separation Deficiencies During walkdowns of selected safety related systems, the team identified many instances of inadequate separation between different safety related electrical cable group Cable separation is required to assure that a single failure or event could not impact more than one train of safety equipmen This requirement is specified in the General Design Criteria (10 CFR 50 Appendix A), the emergency core cooling systems (ECCS)

criteria (10 CFR 50 Appendix K), and the protection systems criteria [10 CFR 50.55a(h)].

Section 8.1.4.2.4 of the Salem Generating Station UFSAR describes the design measures which satisfy these requirement In general, the design criteria for spacing between the four protection channels (A,8, C, and D) are 12 inches vertically and 18 inches horizontall Certain non-safety related cable may be routed with safety related cable (E, F, G and H may route with B, C, D and A respectively).

The cable separation design criteria are implemented through Design Specification CD-S-1, 11 Design Criteria for Independence and Separation of Protection Systems, 11 Salem Design Memorandum No. 30 (Revision 5), and Salem Maintenance Procedure M3K, 11 Electrical Cable Installation/Pulling.

The team reviewed the procedure and found them to be generally consistent with the UFSAR criteria with the addition of guidance for the installa-tion of separation barriers when the required distances were not achievabl The team identified approximately 35 apparent deficiencies to the licensee for review and dispositio The deficiencies were in the Unit 1 Relay Room, the Unit 2 Relay Room, the Unit 1 Control Room - Equipment Room, the Unit 2 Control Room -

Equipment Room, the Unit 1 Electrical Penetration Area, the Unit 2 Electrical Penetration Area, Unit 1 Service Water Intake Bay 1, and Unit 2 Service Water Intake Bay Four typical examples are listed belo Cable 2FW428-AT (Channel A) did not have 12 inches separation from cable 2FW427-BT (Channel B) as they exited trays 2C282 and 2C284, respectively, in the Unit 2 Relay Roo Cable 1RP38-BT (Channel B) did not have 12 inches separation from cable 1B7YC2C-CT (Channel C) at the juncture of trays 1C2K2 and 1C2E5 (Channel 8) with trays 1CJ7 and 1CK4 (Channel C) in the Unit 1 Relay Roo Cable 1VNT367-AT (Channel A) did not have 18 inches vertical separation from 1P076 (Channel C) in the Unit 1 Electrical Penetration Are Cables in tray 2P076 (Channel C) did not have 18 inches vertical separation from cables in tray 2P078 (Channel D)

in the Unit 2 Electrical Penetration Are The number of deficiencies and areas affected is indicative of a programmatic weakness in the assurance of adequate separation of safety related cabl Similar deficiencies were identified in previous NRC inspections (see NRC Inspection Reports 50-272/

90-04 and 50-272/90-05).

Licensee corrective actions in response to the previous findings were not effective in that they appeared to be limited to addressing the inspector 1 s individual findings and did not identify that many other similar deficiencies existe Licensee corrective actions to the team 1 s findings were still in progress at the end of the inspectio Licensee engineers conducted a detailed walkdown of all cables involved in assuring safe shutdown with emphasis on power cable~. Additional separation deficiencies were identified including four involving 230 V power cabl By the end of the inspection, the licensee had corrected many of the identified deficiencies and the development of a long term corrective action program was in progres. RHR Pump Interaction, NRC Bulletin 88-04 After reviewing RHR System drawings, the team found that the RHR system appeared to have a configuration that did not preclude pump to pump interaction during parallel pump operatio The RHR system 1 s pump discharge lines contained check valves upstream of the pump recirculation line The RHR discharge lines in each unit were cross-connected, potentially allowing a much stronger pump to seat the weaker pump 1 s (i.e., the pump with a lower shutoff head) discharge check valve and reduce the weaker pump 1 s flow to zero (

11deadheading 11 ) when the two pumps were operated in parallel. The team then reviewed the licensee 1 s response to Bulletin 88-04, 11 Potential Safety Related Pump Loss. 11 The response concluded that no potential for pump interaction existed in the Unit 1 and Unit 2 Residual Heat Removal (RHR)

systems, and therefore, no corrective actions were require The team brought this finding to the licensee's attention; the licensee did not initially agree that the RHR system was susceptible to deadheadin Following further assessment, the licensee agreed that the potential existed, but stated that the probability of such interaction was remot The licensee performed an analysis to determine the differential pressure (dip) required to close an RHR pump discharge check valve when the pumps were operated jn parallel, and the time at no-flow conditions that would cause pump damag Preliminary analysis concluded that approximately a 10 psi differential between the lA and lB pumps could cause the weaker pump's discharge check valve to shut, causing the deadheading condition described in Bulletin 88-04 to occu Data from the pump manufacturer indicated a time period of approximately ten minutes without flow could cause pump damag The pumps were close enough in pump head performance that the licensee did not believe that pump deadheading would occur when the pumps were operated in paralle The team pointed out that the possibility existed based on plant configuration and that this was in contradiction with the licensee's docketed response to Bulletin 88-0 Further analysis by licensee personnel concluded that the possibility for pump deadheading did exist for the Unit l RHR syste Unit 2 pump suction lines contained check valves which prevented pump-to-pump interactio The licensee was reviewing previous pump performance surveillances to determine whether the pumps had ever indicated differential head capacities of greater than 10 ps This condition would have resulted in deadheading if the pumps had been called on to respond to a small break LOC The licensee decided to complete the requisite analysis for the Unit 1 RHR pump system, and to revise the bulletin respons The team noted that without on-line instrumentation to demon-strate that adequate flow exists for each pump, predictive analysis such as that for the pump-to-pump differential pressures did not guarantee protection against deadheading condition The team considered the licensee's failure to identify and eliminate the potential for RHR pump damage from deadheading due to pump-to-pump interaction during miniflow conditions (as delineated in NRC Bulletin 88-04) to be a significant weaknes.2.8 Non-Code Repairs The team reviewed licensee activities concerning a welded patch repair to a through wall leak of the Unit 1 No. 11 Service Water (SW) header that was implemented by the licensee in January 199 The affected section of SW piping was classified as

Safety Category 1, American Society of Mechanical Engineers (ASME) Class At the time of discovery, Unit 1 was at powe The licensee determined that the leak was the result of a hole approximately 0.8 inches in diamete Since the leak could not be isolated and an ASME code repair could not be completed within the SW TS Action Statement, the licensee made a non-code repai The repair, installed via the licensee temporary modification process, consisted of welding a patch fabricated from safety related pipe over the hole and thin wall locations directly surrounding the hol Before installing the temporary patch, the licensee had performed an ultrasonic examination of the area where the patch was to be welded to ensure adequate structural integrit A permanent code repair of the pipe was scheduled to be made in October 1990 during the upcoming refueling outag Nondestructive examination and a pressure test were performed on the affected section of pipe following the temporary repai The ASME Code Section XI does not accept through wall leakage in a Class 3 pressure boundar The Salem facility is required to meet ASME requirements pursuant to 10 CFR 50.55a (g)(4), with relief request mechanisms specified in 10 CFR 50.55a(g)(5).

The licensee had formally requested relief on several previous occasions, once in 1986 and three times in 198 In all but one case, the relief requested was the use of a non-code repair (weld overlay) to Service Water pipin The NRC transmitted by letter (Mr. James C. Stone, Project Manager, to Mr. Steven Miltenberger, Vice President and Chief Nuclear Officer, dated October 20, 1988) a Safety Evaluation Report (SER) which formally granted the requested relie The SER specifically addressed the history of non-code repairs, the code requirements of 10 CFR 50.55a(g)(4), and the relief mechanisms of 10 CFR 50.55a(g)(5).

The team questioned the adequacy of the temporary repair and encouraged the licensee to discuss the repair with the NRC Office of Nuclear Reactor Regulation (NRR).

NRR indicated that the temporary repair did not satisfy the ASME code and that the licensee was required to request code relief when the leak was initially discovere Additionally, NRR indicated that a temporary repair implemented through a welded patch was not a desirable temporary repair compared to a soft patch due to the potential effects of welding on degraded pipin The team also identified an apparent licensee misunderstanding of the app~icability of the TS to ASME component If the structural integrity of any ASME Code Class 3 piping does not conform to the code, Unit 1 TS 3.4.10.C requires that either structural integrity be restored or the affected component(s) be isolated from servic The licensee stated that the above

Limiting Condition for Operation (LCO) did not apply because the LCO was contained in the Reactor Coolant System chapter of Unit 1 Technical Specification There are no ASME Code Class 3 components in the Reactor Coolant System and the NRR position 1 was that the LCD should have applied to all ASME code component Before the close of the inspection, the licensee was in contact with cognizant NRR management to resolve the non-code repair and TS applicability issue.2.9 Scaffolding The team noted that there was a substantial amount of scaffolding erected in safety related areas, including some in Unit 1 which was preparing to start u In particular, scaffolding was around and over an operating component cooling water pump and close to an operable EO The team expressed the concern that scaffolding could impact the operability of safety related equipmen Scaffolding was controlled via three documents:

Administrative Procedure No. 23, 11 Sea ffo l ding and Transient Load Program,

(AP-23), Field Directive No. S-C-A900-SFD-278, 11 Use and Control of Scaffolding in Safety-Related Areas, 11 and the Nuclear Department Safety Manual,Section XI, 11 Ladders, Scaffolding, Floor and Wall Openings and Stairways.

The procedures were found to be of good quality in the technical construction aspects of scaffoldin Inspections were required before use and frequently during us However, the team made the observa-tion that, while irspections were required monthly when the scaffolding was not in use, there was no procedural limit on the length of time unused scaffolding could be left over or near operable safety related component Additonally, one inconsistency was noted in that the Field Directive (Revision 4, 2/4/87) stated that AP-23 would be deleted (and deleted AP-23 as a reference), but AP-23, which was revised in May 1989, is considered by site personnel to be the controlling procedur The team noted that the above inconsistency had been previously identified by the licensee in a review completed for a January 16, 1989 event (see LER 50-311/89-24) in which the fall of a scaffold piece caused an EOG auto star This review (an LER commitment) recommended a number of Field Directive changes, some of which were intended to help preclude a repeat event, but no revision had been made by the time of the inspectio The licensee stated that scaffolding would be addressed in the planned site-wide procedures, but that this procedure was not on the current schedule (which went to the end of 1990).

Guidance on scaffolding clearances to safety related components was part

of the review 1 s recommendations to preclude another plant even Failure to implement the results of the review in a timely manner is considered by the team to be a weakness in corrective actio The team identified weaknesses in the licensee 1 s control of scaffolding in that no procedural limits existed for the length of time that unused scaffolding could be left over or near safety related equipment, and licensee identified corrective actions were not implemented in a timely manne.3 CONCLUSIONS The design process within Engineering and Plant Betterment was well controlle Some system engineers demonstrated deficient system knowledge of equipment for which they were responsible, and a lack of system engineer field presence and attention to detail was note Reviewed plant modification packages and drawings affected by the modification process were found to be satisfactor There was misuse and a lack of management control of the T-MOD process, as evidenced by recent marked increases in the number of active T-MODs, the failure of SORC to review all active T-MODs since January 1990, and a number of permanent modifications implemented as T-MOD The Technical Department did not trend equipment performance dat Significant deficiencies were identified in electrical cable separation, control of scaffolding constructed over safety related equipment, and in the licensee's response to NRC Bulletin 88-04, 11 Safety Related Pump Loss.

11 SAFETY ASSESSMENT/QUALITY VERIFICATION SCOPE In reviewing this area, the team selected a sample of attributes which are key contributors to assuring safety and verifying qualit Among the selected attributes were plant material conditions, procedure quality, tracking and trending mechanisms, the safety evaluation process, and work activity contro The team specifically as-sessed management involvement, control and oversight of each attribut. 2 FINDINGS 5.2.1 Material Deficiencies The team conducted a general site walkdown, with emphasis on areas containing safety related systems such as the reactor containment and auxiliary building Detailed walkdowns of

selected key safety systems were also performed, sometimes accompanied by the cognizant system engineer (see Detail 4.2.2).

Many deficiencies were identified and the team-identified items were then compared with the licensee's lists of self-identified item Items found to be previously identified were evaluated for adequacy of planned corrective action New items were assessed for potential significance and causative factors for the licensee's failure to identify the deficiencies were evaluate The team found the overall material condition of the areas examined to exhibit substantial weaknes A large number of tags denoting deficient conditions were observed on various components by the team indicating that efforts were being made to correct problem The tags were often illegible (the licensee plans to implement improved tags), loose or vague such that the team judged that new and separate deficiencies on a tagged component might not be identified for correctio Further, the team identified many specific component deficiencies which had not been previously identified by the license The following are some examples:

Corrosion was visible on portions of both containment building liner The lower 34 feet of each liner is generally covered by insulatio Rust was visible on certain portions visible through gaps, on retention studs, and on the floor at the liner bas The licensee stated that 2n engineering evaluation woula be performed during the next refueling outag Teflon tape was found to be used to seal certain threaded pipe connection The licensee's initial position was that instances of teflon tape use were isolated in nature, that it was not used in the containment buildings, and that the May 22, 1985 Field Directive No. S-C-A900-MFD-290, "Use of Nuclear Grade Grafoil Thread Sealant Tape, 11 would be re-emphasize Accompanied by licensee personnel, the team conducted a partial walkdown of both containments and identified numerous applications of teflon tap Additionally, two rolls of teflon tape were identified available for use in the containment I&C work cag No examples were identified of use on environmentally quali-fied electrical connections and licensee evaluation was still in progress at the end of the inspectio Numerous packing leaks were identified in the Unit 1 containmen Some of the leaks involved heavy boron crystal encrustation of valves and surrounding area, indicating the leaks had existed for a considerable period of tim Unit 1 had been in an unscheduled shutdown for five weeks and was preparing to startu There was no indication of any effort to correct the deficiencie Significant portions of the Unit 2 auxiliary building drain piping were heavily corroded and leaking at several location The leaks, located in the overhead, were a potential hazard to personnel and operating equipmen A similar problem had been identified at Unit 1, but there was no evidence that Unit 2 piping had been checked for the same proble After identification by the team, the licensee added thi~ item to the proposed design change packag Flexible conduits protecting safety related cables associated with valves 12-MS-167 and 14-MS-167 were damaged and the cables expose The conduits were satisfactorily repaired before the end of the inspectio Other deficiencies were followed up as separate engineering issues, namely, inadequate separation of safety related cable (Detail 4.2.6), RHR pump interaction (Detail 4.2.7), non-code repair of ASME Class 3 service water piping (Detail 4.2.8), and control of scaffolding (Detail 4.2.9).

Certain other deficiencies of a more general nature are listed belo The team considered these deficiencies, in the aggregate, to be a significant weakness and to be indicative of an unacceptably high tolerance by the licensee of degraded condition Doors on the nuclear instrumentation (NI) cabinets were found open and one door was missin This problem was identified by the licensee in 1986, and involved the cables inside the cabinets in that, the number of cables and restrictions on cable bend radius prevented door closure (due to possible cable crimping).

Initial efforts to modify the cable or connectors were not successfu Current plans involve changing the door design to accommodate the existing cable In the four year interim, however, the doors have remained ajar (or removed) and therefore vulnerable to inadvertent kicking or closure which could potentially generate spurious NI signals or damage the safety related cabl The licensee posted warning placards locally before the end of the inspectio Instances were observed where leaks inside marked contaminated areas had created puddles across taped boundaries and into 11 cl ean 11 areas and walkway The team observed that numerous licensee personnel passed by or stepped over the puddles, but no action was taken until team members brought the issue to the attention of Radiation Protection personne The team observed severe stem scoring and damage on valve 1-CV-55 due to the practice of instrument and controls technicians rotating the valve stem with a pipe wrench during conduct of routine surveillance test Ultimately, this resulted in the inability of the operators to set the valve so it could be returned to its fully closed positio Licensee evaluation of the impact of the scoring and damage on the reliability of the valve was in progress at the end of the inspectio Some fire doors were found propped open without the required permit Other doors were found which failed to automatically shut completely after being opene In both containments, oil leaks had rendered floors, decking, catwalks and ladders hazardous, particularly since personnel in the impaired areas were required to be in anti-contamination clothing with vinyl shoe cover Area lighting was inadequate in parts of both containment and auxiliary building The use of flashlights was required to traverse some area In at least one case, there was a significant hazard to personnel involving a combination of poor lighting, missing guard rail, and oily deckin Unsecured equipment and compressed gas bottles were observed in the Unit 1 (preparing to startup) auxiliary buildin These items were secured or removed by the end of the inspectio.2.2 Material Improvement Initiatives The team noted two licensee initiatives that were in progress to improve plant material condition The first involved periodic walkdowns for station management and the second was a material improvement progra In 1988, the General Manager - Station Manager Operations (GM-SO) began a program to improve the identification of material and housekeeping deficiencie The program consisted of weekly station walkdowns by the GM-SO and other station manager The walkdowns usually concentrated in a different location and functional area each wee The front line supervisors of the functional area being inspected also parti-cipated in the walkdowns to improve commu.nication and share insights with station managemen The team found that even though the walkdown program was not formalized in a station procedure, material deficiencies were being identified, tracked and corrected on a timely basi In addition, during walkdowns, selected previously identified deficiencies were reviewed as a follow-up measure to ensure that the deficiencies were being correcte The team was informed that the management walkdown program was in the process of being formalized in a station procedur The team noted that the licensee had initiated a material improvement progra The licensee had identified several systems which were significantly degraded and therefore allocated substantial resources during each refueling outage to system repair or replacemen Discussions with the licensee indicated that the majority of the resources allocated for the program were expended on degraded balance of plant system One safety related system where the licensee had made extensive repairs was the Service Water System of both unit Significant parts of the service water headers were heavily corroded and the licensee had initiated a multi-year program to replace the affected carbon steel piping with 6% molybdenum stee The team noted during plant tours that there still existed significantly deg~aded portions of service water system (the program was about half completed at the time of the inspection), especially in Unit The team considered these two activities to be positive initiatives, but the team noted that, overall, the Salem facility exhibited weakness in material (Ondition (see Detail 5.2.1).

5.2.3 Station Qualified Reviewer Process TS 6.5.1.6.a requires the Station Operations Review Committee (SORC) to review changes to existing procedures that involve a Significant Safety Issue (SSI).

If an SSI is not involved, then the TS allow procedure changes to be executed through the Station Qualified Reviewer (SQR) proces TS 6.5.3.2.C requires

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that individuals responsible for reviews of newly created procedures, programs, or changes thereto 11 shall be approved by the SORC Chairman and designated as SQRs, 11 and that a system of SQRs shall be maintained by the SORC Chairma The SORC Chairman had delegated the maintenance of this TS requirement to the SQR Coordinato As of May 11, 1990, there were 124 SQRs at Sale The team reviewed licensee controls for maintaining a system of SQRs and had the following significant finding As part of the licensee 1 s corrective action to NRC Violation 50-272/89-17, the licensee committed to provide additional training to SQRs by October 1989 to ensure that they remained fully aware of SSI requirements and the appropriate procedural requirements resulting from Administrative Procedure (AP)

rev1s1on The team identified that, as of May 25, 1990, a significant number of SQRs had not received this trainin The team also identified that the SORC Coordinator was not aware of the SQR training commitmen In addition, the licensee had made no attempt to restrict those individuals who had not received the training from performing SQR dutie The team reviewed a number of surveillance procedure changes to determine if they had received appropriate review and approval prior to implementatio Salem TS 6.5.3.2.a and the licensee's procedures require that procedure changes be independently reviewed by an SQR, who is an individual knowledgeable in the subject area, but is other than the originator of the specific procedure chang The team noted that a January 8, 1990 change made to SP(O)

4.0.5-P-RH-12, 11 Inservice Testing - Residual Heat Removal,

appeared not to have received an independent review, because the Technical Department engineer who completed the related design change package and determined that a procedure change was needed had also signed the procedure change notice as SQ In addition, the team noted a discrepancy in the procedure change in that steps were not taken to ensure that root valve 12RH80 would be closed following testin These steps were necessary because the design change package took credit for closure of the root valve in all cases except during testing in order to justify the decision to not seismically qualify a newly installed pressure gage suppor The team questioned several licensee representatives regarding the independence of SQRs and received various response Some stated that the procedure change initiator is the most appro-priate person to serve as SQR because that individual would be most familiar with the chang Others stated that when an individual determines that a procedure change is needed, as long as a separate person writes the procedure change and signs as author on the procedure change notice, it is acceptable for the first person to act as SQ The team disagreed with both positions and would instead expect that the person determining the need for the change would prepare it and a separate, independent SQR would review i The team discussed this apparent lack of SQR independence with licensee management who agreed that the process, as implemented, did not provide SQR independenc The licensee stated that a Quality Assurance department finding in late 1989 also identi-fied occasions when SQR reviews were not independen The licensee implemented corrective actions to prevent recurrence through the April 30, 1990 revision of AP-32, 11 Implementing Procedures Program."

The team, however, i dent i fi ed a subsequent example of failure to maintain SQR independence when, on May 23, 1990, the engineer who determined that changes were necessary for SP(O) 4.0.5-P-RH(ll) (and, in fact, presented the changes at

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a SORC meeting), also served as the SQ Failure to indepen-dently review procedure changes is an apparent violation of TS 6.5.3. Furthermore, corrective action initiated in response to an earlier licensee identification of the problem was insufficient to prevent recurrenc Based on the licensee's failure to fulfill a commitment to provide SQR training in response to an NRC violation, ensure independent procedure change reviews per TS 6.5.3.2.C, and conduct SORC reviews for procedure changes involving safety significant issues (Detail 5.2.9), the team considered the SQR process not to have been implemented in accordance with the requirements or intent of TS 6.5.3. This is a significant weaknes.2.4 Quality Assurance Organization As part of the Safety Assessment/Quality Verification inspec-tion, the team reviewed the structure and effectiveness of the Salem Quality Assurance/Nuclear Safety Review (QA/NSR) organi-zatio Portions of the organization covered by the review included the Offsite Safety Review Group (OSR), the Salem Onsite Safety Review Group (SRG), and the Salem Station QA Departmen Also inspected in this functional area was the Reliability and Assessment Group, which was not part of the QA/NSR Department, but instead reported directly to the Vice President Nuclear Operation The team interviewed the head and various members of each of the above-mentioned QA departments and examined the Sal~m Technical Specifications and the licensee procedures that defined each department's organization and responsibilitie The team also reviewed several reports and audits prepared by these depart-ment The team determined that the OSR function was well defined in both TS cind in procedures VPN-MSP-08, 11 Nuclear Safety Review

and GM9-SRP-03, 11 Independent Safety Review Program.

The SRG was required by TS, but was not as well defined as OSR, and along with Station QA, was guided in function by the 11 Quality Assurance - Nuclear Safety Review Department Manual.

All QA organizations were well managed and had the staff and flexibi-lity to accomplish their chartered goal The reviewed audits and reports were thorough and demonstrated acceptable performance of the individual QA department The audits and reports contained accurate and meaningful assessments of licensee programs and performanc In addition, the reports provided comprehensive recommendations to improve or correct identified deficiencie The team identified no significant weaknesses in the organiza-tion or performance of the individual QA/NSR department A concern was noted, however, in the timeliness and manner of response by licensee management to QA/NSR finding This concern was also identified in the most recent NRC Systematic Assessment of Licensee Performance (SALP Report Numbers 50-272/88-99 and 50-311/88-99).

The team investigated the resolution of deficiencies identified in QA/NSR reports, particularly in OSR and SRG reports, and found that follow-up of these weak areas or deficiencies was not controlled and, in some cases, was delinquen Unless a specific corrective action was logged into and tracked by the Action Tracking System (ATS),

resolution of the item often depended on personal initiative and was not controlled by management follow-u.2.5 Tracking and Trending The team found that the Performance Indicator Program, while not controlled by procedure, was a positive asse Performance indicators were compiled, tracked, and reviewed by plant management on a monthly basis to assess plant trend The Executive Information System maintains these performance indicators in a computer data base that was available to all upper plant managemen The team found that the Station Quality Assurance (QA) group was effectively tracking and trending QA concern The team reviewed QA open items and trend The number of outstanding QA items was consistently low, indicating QA open items were being addressee by the licensee on a timely basi The licensee's Action Tracking System (ATS), as defined in NC.NA-AP.ZZ-0057(Q),

11Action Tracking Program, 11 was a tracking mechanism for all Nuclear Department action item The team reviewed the three reports issued using ATS dat The three reports were: the ATS Open Item Report, which lists all open and past-due ATS action items; the NQA report, which lists all Station QA Action Requests within 30 days of their due date; and the Category 1 Report, which lists all external dated regulatory requirements within 30 days of their due dat The team determined that the ATS was a good data base of action items and commitments that had been opened at the station, and the system provided an adequate means of tracking their closur The organization of the system and the personnel implementing it had effectively entered items into the AT During the review of the ATS reports, the team found that no QA Action Request or Category 1 action items had been past due since July 198 The ATS Open Item Report, however, listed 348 out of the 598 (58%)

total ATS open items as beyond their due date at the time of

the inspectio The ATS items were not tracked by priority (a Priority of 1 through 4 was assigned to each item as a measure of its safety significance), which made it difficult to assess the safety significance of the overdue item The team reviewed trending of plant events and associated corrective action All Incident Reports and significant plant action items were tracked in the ATS for closure, but the information was not trended in any significant manne Various QA organizations had audited the event history, but this was not controlled by any integrating procedure and resulted in a list of findings or corrective actions that were not always followed up by station managemen The team identified two cases where a problem had been identified and corrected at one unit without the other unit being informed, only to have the same problem occur later at the second uni The licensee's use of tracking and trending was inconsisten Tracking and trending of performance indicators and QA open items was found to be a strengt Weakness, however, was exhibited in tracking and trending of plant events and equipment performance (see Detail 4.2.5).

5.2.6 Significant Event Response Team The team reviewed a recently (March 15, 1990) implemented licensee initiative, the Significant Event Resronse Team (SERT).

The purpose of SERT was to improve the assessment and resulting corrective action(s) following significant events by providing a structured method of performing multidisciplinary, independent evaluations of events for root cause determination and corrective action recommendatio The SERT program was governed by Nuclear Administrative Procedure NC.NA-AP.ZZ-006l(Q).

The procedure required that a SERT be formed following all reactor trips, all safety injec-

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tions, or for any other event or concern at the discretion of the Station Manager or Nuclear Department Vice Presiden The SERT leader or manager was required to be a non-station manager to assure independence of the SERT from routine station investigation and reporting activitie SERT managers and team members had received specialized training in root cause analysis and interviewing technique To provide a multidisciplinary investigation, members of the SERT team were to be provided from a variety of departments, including Maintenance, System Engineering, Operations, Technical Staff, Quality Assurance, Radiation Protection, Nuclear Safety Review, and Trainin The goal of each SERT was to provide a comprehensive report within seven days following the event or concern identificatio The team reviewed several SERT reports and found the reports to be generally of high qualit The SERT investigations and root cause determinations were comprehensive and detaile The team found that the SERT corrective action recommendations were being implemented and tracked in the licensee Action Tracking System (see Detail 5.2.5)-.

An exception to the normally high quality SERT reports was a report concerning an April 19, 1990 Unit 1 trip resulting from the loss of a main feedwater pum The report lacked adequate detail and the root cause determinations were unclea Notably, the Station Manager reviewed the report, recognized the deficiencies, and immediately ordered the Onsite Safety Review Group (OSRG) to perform an additional independent review of the even The team reviewed the OSRG report and found it to be of hi g h qua l ity.

The licensee SERT program was found to be a notable strengt Generally, SERT assessments and recommended corrective actions were comprehensive and detaile The Station Manager 1 s recognition of an inadequate SERT report and subsequent initiation of an OSRG independent review was also considered a strengt.2.7 Configuration Baseline Documentation The Configuration Baseline Documentation (CBD) project is a long term initi~tive intended to reconstitute the design bases for many of the major plant system The initial benefit of the CBD project is in support of the licensee 1 s effort to increase the rating for the Salem unit Accurate design basis information is essential to assess margins of safety for existing systems and for planned modification The CBD project was initiated in May 1988, with an estimated duration of five year The bulk of the engineering effort is staffed from outside contractors (~bout 50) with a few licensee personnel providing supervision and oversigh At the time of the inspection, nine system CBD reports had been issued with thirteen other reports under review, and data collection for another eleven in proces The team selected two CBD reports for review involving the control air and auxiliary feedwater system The reports were found to be of high qualit Gaps in historical documentation were identified by the reports, tracked for resolution, and resolve In some cases, engineering analyses were performed to verify adequacy of in situ systems when original calculations could not be foun.,

The team considered the CBD project to be a notable initiative involving substantial resources and management commitmen.2.8 Procedure Upgrade Program The team conducted an extensive review of the Procedure Upgrade Project (PUP).

The PUP was developed and approved in June 1989 as a corrective action for the numerous procedure inadequacies which had been previously identifie A great number of human factors and technical accuracy concerns had been raised regarding procedures associated with several prior incident The PUP was intended to provide the site with procedures that were technically correct and consistent in the format outlined in the 11Artificial Island Implementing Procedure Writers Guide.

Computerized data bases were being developed in order to efficiently maintain all procedures in the futur Interviews were conducted with the PUP Manager, Project Admini-strator, research review personnel, procedure writers, and PUP Station Qualified Reviewer The objectives of PUP were noted as both ambitious and challengin The scope of the project is extensiv However, the resources necessary for the success of the project were underestimated by licensee managemen At the time of the inspection, nearly a year after PUP approval, only ten procedures had been issued by the PU The Project Tracking System indicated that approximately 1250 procedures should have been issued by that dat The project appeared to be at a standstill at the time of the inspectio Qelays in the established project process were the result of:

underestimation of the time required to develop the human resources necessary for the project, utilization of personnel with experience in the PUP by upper management for response to scheduled plant outages and reactive events rather than exclusively for the PUP, revision of project goals and scope by management on numerous occasions since conception (with the intent of improving the end product),

redirection of PUP resources to meet the requirements of the delinquent biennial procedure review process, (See NRC Inspection keport 50-272/90-11; 50-311/90-11)

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commitment of the PUP process for Operating Procedures has been to the creation and modification of special reactive test procedures, specifically, the Charging and Safety Injection pump flow and flow balance verification test delays in the required field approval by Operations, Maintenance, or I&C management of many of the over 1000 procedures which have been drafted by the PU In conclusion, the PUP was developed as a corrective action to problems and events caused at least in part by procedure inadequacie As such, the PUP is a positive and much needed initiativ The team, however, concluded that weakness was exhibited in the licensee's prosecution of the progra Licensee senior management expressed strong commitment to the PUP and stated that program processes, resources, and schedules would be reassesse. Safety Evaluation Process The team reviewed a sampling of permanent and temporary facility modifications and procedure changes to assess the licensee's application of 10 CFR 50.5 Licensees are permitted by 10 CFR 50.59 to "make changes in the procedures as described.in the safety analysis report

... unless the change, test, or experiment involves a change in the Technical Specifications incorporated in the license or an unreviewed safety question.

The team identified many instances where these requirements had been misapplied for bot~ procedure and facility change The team identified two examples involving misapplications of 10 CFR 50.59 for facility change In the first case, the licensee used a 10 CFR 50.59 safety evaluation to justify the installa-tion of a non-code repair (Detail 4.2.9).

Secondly, the licensee failed to conduct a 10 CFR 50.59 safety evaluation when

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an eroded containment fan cooling unit was modified through the use of Belzona 11 R 11 metal (Detail 4.2.2).

The team also identified a number of procedure changes, conducted through the SQR process, where required 10 CFR 50.59 safety evaluations were not conducte Examples included SJ.OP-ST.SJ-0013(0) Rev. 1, which was revised to include additional acceptance criteria, and SP(0)4.0.5-P-RH(l2) Rev. 10, which was revised when an additional suction pressure gauge was added to an RHR pum The former example was of particular concern to the team because it was the product of the PUP process, the licensee stated that PUP procedures would not receive SORC review, and the procedure was not adequate for use without revisions (see Detail 2.2.3).

Additional examples are discussed in Detail 3. The team observed that the primary reason for the 10 CFR 50.59 misapplications resulted from the incomplete screening criteria used by the licensee in determining 10 CFR 50.59 applicabilit The criteria were too narrow and led the user to a determination that a safety evaluation was not needed unless the item being changed was explicitly described in the safety analysis report (SAR).

The majority of licensee personnel contacted on this issue expressed agreement with the guidance found in Attachment 6 of AP-32, "Implementing Procedures Program, 11 which stated that, 11 if a procedure is not contained or described in the SAR, the procedure may be changed and a 10 CFR 50.59 safety evalua-tion is not neede If a procedure is simply listed (and not outlined, summarized, or completely described) in the SAR, the procedure may be changed and a 10 CFR 50.59 safety evaluation is not required.

The team maintained that this guidance was incomplete and focused too heavily on SAR content instead of the safety significance of the chang For example, a procedure change can result in operating a system differently than described in the SAR or assumed in safety analyses, even if the procedure itself is not in the SA Additionally, the team identified discrepancies between Salem procedures which covered the 10 CFR 50.59 safety evaluation proces DE-AP.ZZ-008, 11 10 CFR 50.59 Reviews and Safety Evaluations, 11 contained a broader definition of 11 procedures as described in the SAR, 11 when compared to the narrow guidance found in Attachment 6 of AP-32, as described abov The team noted that station management also misunderstood 10 CFR 50.59 requirement When the issue was discussed with station management, they stated that the guidance of AP-32 was consistent with that found in NSAC (Nuclear Safety Analysis Center) 125, "Guidelines for 10 CFR 50.59 Safety Evaluations."

The team further reviewed AP-32 Attachment 6 and found that the licensee had incorporated NSAC 125 guidance only in part, and omitted amplifying information on procedures changes 11 as described in the SAR.

NSAC 125 states that, 11 procedures are

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not limited to those items specifically identified as procedures

..., but SAR procedures include anything described in the SAR that defines or describes activities or controls over functions, tasks, reviews, tests, or safety review meetings.

SQRs are allowed by TS 6.5.3.2 to review procedure changes in place of a SORC review if a safety significant issue does not exis The process was initiated to allow increased SORC attention to safety significant review items by reducing the amount of routine and insignificant procedure changes requiring SORC revie Use of the SQR process, h6wever, allows implementation of procedure changes without a multidisciplinary revie The number of procedure changes conducted without

required safety evaluations (and consequent SORC reviews)

indicated misuse of the SQR proces The team reviewed DE-AP.ZZ-0008(0) and noted that it contained a very limited listing of examples that were considered not to be 11 changes in the facility as described in the SAR 11 (e.g., typographical changes and drafting errors).

Further, the procedure described a more limited scope of procedure changes allowable through the SQR process than observed by the team to be in practic The team found licensee safety evaluations, when completed, to be of high qualit The concern remained, however, regarding the misuse of the SQR proces It would appear that in an effort to reduce the review burden on SORC, the licensee limited the issues receiving 10 CFR 50.59 evaluations to a level below that allowed by regulation and TS 6.5.1. Additionally, weaknesses were noted in the SQR process regarding the lack of independent reviews and training inadequacies (see Detail 5.2.3).

5.2.10 Control of Overtime The control of overtime (OT) was one of the regulatory issues contained in NUREG-0737, 11Clarification of TMI Action Plan Requirements, 11 which was issued in November 1980 (Item I.A.1.3).

Further regulation review led to modifications of the require-ments as described in Generic Letters 82-12 and 83-1 Salem Unit 1 and 2 Technical Specification (TS) 6.1.f stated that overtime must be limited in accordance with Generic Letter 82-12 and the numerical limits on OT hours were captured in the licensee 1 s Administrative Procedure (AP) 5, 11 0perating Practices Program 11 (see Attachment 2).

Generic Letter 82-12 states 11 Recognizing that very unusual circumstances may arise requiring deviation from above guide-1 ines, such deviation shall be authorized by the plant manager or his deputy, or higher levels of management.

11 (emphasis added)

The clear regulatory position is that personnel should normally work an 8-hour day, a 40-hour week, that OT should be controlled with prescribed limits, and that senior management should authorize exceptions only for very unusual circumstance The team identified numerous instances where overtime in excess of the TS limits were worked without prior authorization or were improperly approved by group managers not authorized to make the approva The team reviewed overtime records for the months of March and April 1990, the two months immediately prior to the inspectio Inadequate control of OT was found in all departments covered by the Generic Letter, namely the Operations, Maintenance, and Radiation Protection Department The team identified that three non-licensed equipment operators had exceeded the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period limit during the month of April without prior approval of the General Manager-Station Operations (GM-SO).

The GM-SO had signed the OT approval authorization form AP-5-1 after the limits had been exceede Discussions with Operations Department staff indicated that the authorization of OT beyond the limits after the limits had been exceeded was a routine practic The team found that at least ten Maintenance Department personnel, covered by AP-5 limits, who had exceeded the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period limit and/or the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period without prior authorizatio In addition, at least thirteen Maintenance Department personnel exceeded the OT limits with prior authority, but the authorization was not granted by the GM-SO as required by AP-5, and there was no writte delegation of this authorit Two Radiation Protection technicians were identif5ed as having exceeded the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in seven day limit without prior authorit In addition, the Radiation Protection overtime tracking system failed to identify that the individuals had exceeded the AP-5 limits and, therefore, post-OT authorization was never grante There were also several Radiation Protection personnel who exceeded the AP-5 limits with preauthorization from other than the GM-SO, which is contrary to AP-Discussions with station management initially indicated that the approval of overtime in excess of the AP-5 limits after the overtime li~its had been exceeded and the approval of excessive OT by managers other than the GM-SO were acceptable practice Senior site management participated in later discussions with the team and stated that the licensee 1 s official position was that OT in excess of AP-5 limits required pre-approval and that this position would be more clearly communicated to the rest of the organizatio The licensee also committed to review this issue to determine which individuals had the authority to approve OT beyond AP-5 limit In summary, excessive OT was found to be routinely worked without prior authorizatio In addition, permission to work excessive OT was routinely granted by licensee personnel other than the GM-S Station management willingness to condone noncompliance with AP-5 requirements was noted as a weakness in

licensee commitment to procedural adherenc This was indicative of a loss of oversight by Jicensee senior managemen The team considered the licensee's failure to control overtime usage in accordance with TS to be a significant weaknes.3 CONCLUSIONS The team found two licensee initiatives to be notable strength Both the CBD and SERT programs were functioning well and producing high quality result The performance of individual groups in the QA/NSR appeared to be a licensee strength, however, the team found that recommended corrective actions of some QA/NSR groups were not controlled and in some cases were delinquen The team also found the licensee's use of tracking and trending to be inconsisten Some management-sponsored improvement programs appeared not to be effective in achieving timely corrective actio Despite initiatives to improve the material condition of the plant equipment, the team found the overall material condition to exhibit substantial weaknes The PUP, a much needed corrective action, was found to be signifi-cantly behind schedule and a PUP procedure reviewed by the team required several revision The team found significant weaknesses in licensee management's oversight of several activitie The SQR process was not being implemented in accordance with Technical Specification requirements, in that the process was used to implement procedure changes involving safety significant issues and SQR independence was not always maintaine Insufficient corrective action was indicated by the licensee's failure to provide special training, committed to in response to an NRC violation, to all SQR Additional examples of ineffective or untimely corrective action include the Nuclear Instrumentation cabinet doors (Detail 5.2.1),

electrical cable separation deficiencies (Detail 4.2.6), and the delays in Procedures Upgrade Program (Detail 5.2.8).

Safety e¥aluations required for changes to plant equipment were not always performe Additionally, excessive overtime was routinely worked without prior approval or with unauthorized approval contrary to Technical Specification requirement.

Management Meetings The team held daily meetings with the licensee management to discuss inspection finding The team held a preliminary exit meeting on May 24; the final exit meeting was held on May 2 ATTACHMENT 1 Boric Acid Transfer Pump Performance Data In reviewing the available pump performance records, the team noted that the licensee accepted the following examples of degraded BAT pump performance without 10 CFR 50.59 safety evaluations to justify continued operabilit As listed below, the worst recorded condition was 42 gpm from the No. 22 BAT pump on June 12, 198 NOTE:

21 BAT pump 7/15/87 2/24/90 56 gpm 53 gpm 12 BAT pump 12/1/86 9/87 5/06/90 50 gpm 48 gpm 72 gpm 22 BAT 7/18/87 6/12/88 5/09/90 11 BAT 6/14/88 11/88 3/29/90 pump 48 gpm 42 gpm 49 gpm pump 58 gpm 55 gpm 81 gpm This listing does not represent a complete history of BA pump performanc It was compiled from the limited records provided to the team for review during the IPAT inspectio..

(5.10)

ATTACHMENT 2 Overtime Limits per AP-5, 110perating Practices Program

Overtime Guidance Limits shall be applied to the overtime for licensed Operators, Equipment Operators, Utility Operators, Radiation Protection and key Maintenance personne Key maintenance personnel are those personnel who are responsible for the correct performance of maintenance, repair, modification or calibration of safety-related structures, systems or components, and who are personnel performing or immediately supervising the performance of such activitie (5.10.1)

All Departments responsible for the performance of the above activities shall adhere to the following guidelines: An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight (excluding shift turnover time). An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period (all excluding shift turnover time). A break of at least eight hours which includes the time for shift turnover should be allowed between work period The use of overtime should be considered on an individual basis and not for the entire staff on shift, except during extended shutdown period (5.10.2) Circumstances requiring deviation from the above guidelines shall be authorized by the General Manager -

Station Operations (GM-SO).

The paramount consideration for such authorization shall be that significant reductions in the effectiveness of operating personnel would be highly unlikel (5.10.3)

Deviations to the working hour guidelines shall be documented on an Overtime Authorization (Form AP-5-1).

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APPENDIX SUMMARY OF OPEN INSPECTION ITEMS UNR 90-81-01:

An Emergency Operating Procedure (EDP) tool box inventory surveillance procedure was performed and identified missing gasket No corrective action was taken to replace or identify the location of the missing gasket (Details 2.2.4 and 3.2.4)

UNR 90-81-02:

The Station Operations Review Committee (SORC) failed to review active temporary modifications in accordance with established procedure (Details 2.2.4 and 4.2.4)

UNR 90-81-03:

An emergency diesel generator surveillance was performed numerous times with instrumentation, identified as being required to demonstrate operability, being out of servic No corrective action was inititated to restore the instrumentation to service or change the procedure to more accurately define operability requirement (Details 2.2.4 and 3.2.4)

UNR 90-81-04:

Surveillance procedure SP(O) 4.1.2.lB check off sheet 2-2, step F was not performed as written during performance of the surveillance on April 29, 199 (Detail 2.2.4)

UNR 90-81-05:

Incident reports were not written for several events which warranted such documentation per procedure NA-AP-006.* (Detail 2.2.4)

UNR 90-81-06:

The emergency diesel generator (EOG) surveillance test procedures did not include verification of TS 4.8.1.1.2.b and TS 4.8.1.1.2. (Detail 3.2.2)

UNR 90-81-07:

EOG surveillance test procedures SP(O) 4.3.2.l.(A)4 and SP(O) 4.8.1.1.2.C.7.A/B/C did not include acceptance criteri (Detail 3.2.2)

UNR 90-81-08:

The licensee determined that substantial changes to specific EOG test procedures were not safety significant issue The procedures were changed through the Station Qualified Reviewer (SQR)

process and therefore did not receive Station Operations Review Committee (SORC) review or approva (Detail 3.2.2)

UNR 90-81-09:

The licensee documented minimal deficiencies in performing PI/S-CONT 1, 11 Containment Walkdown, 11 on March 31, 199 Conversely, the team identified numerous (and in some cases, long standing) deficiencies in both containment (Details 3.2.4 and 5.2.1)

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UNR 90-81-10:

The team noted that the No. 11 Boric Acid Transfer (BAT)

pump inservice testing (IST) procedure performed on December 10, 1989 contained a miscalculation in the data shee The differential pressure across the pump was incorrectly calculated and resulted in a value significantly below the acceptable total discharge head required for the BAT pump Nevertheless, the test was accepted by the Operations and Engineering department While the actual value was within the limits specified by the procedure, this issue indicated inadequate review of surveillance test result (Detail 3.2.4)

UNR 90-81-11:

Inservice testing of the BAT pumps was characterized by the licensee as successfully completed in spite of degrading BAT pump perfor-mance beyond the licensing basi This issue illustrated basic program-matic weaknesses and was indicative of poor management oversigh (Detail 3.2.5)

UNR 90-81-12:

The Technical Department did not trend 11 as found 11 instru-mentation calibration dat This data was not recorded on the instrument calibration data sheet (Detail 4.2.5)

UNR 90-81-13:

The team identified many instances of inadequate separation between different safety related electrical cable group The number of deficiencies and area affected was indicative of a programmatic weakness in separation of safety related cabl (Detail 4.2.6)

UNR 90-81-14:

The team identified the potential for pump to pump inter-action within the residual heat removal syste However, the licensee's response to NRC Bulletin 88-04, "Potential Safety Related Pump Loss,"

stated that the potential did not exist, and the licensee had no correc-tive actions in progress or planne fDetail 4.2.7)

UNR 90-81-15:

The licensee installed a non-code repair to ASME Class 3 service water piping without prior NRC approva (Detail 4.2.8)

UNR 90-81-16:

SQR independence for procedure change reviews was not maintained as specified in TS 6.5.3. (Detail 5.2.3)

UNR 90-81-17:

The team identified instances where procedure changes involving safety significant issues were implemented through the SQR process instead of receiving SORC review and approval as specified in TS 6.5.1. This practice was indicative of misapplication of 10 CFR 50.59 requirements and misuse of the lattitude provided by the SQR proces (Details 3.2.2 and 5.2.9)

UNR 90-81-18:

A weakness in corrective action implementation was indi-cated by the licensee's failure to provide special training, committed to in response to an NRC violation, to all SQR (Detail 5.2.3)

UNR 90-81-19:

Excessive overtime was routinely worked without prior approval or with an improper level of approval contrary to that allowed by the Technical Specification (Detail 5.2.10)

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UNR 90-81-20:

Instances of ineffective or untimely corrective action were identifie Examples included the nuclear instrumentation cabinet doors issue (Detail 5.2.1), electrical cable separation deficiencies (Detail 4.2.6), a lack of follow-up for certain Quality Assurance department findings (Detail 5.2.4), untimely improvements to scaffolding control procedures (Detail 4.2.9), and the delays in the Procedures Upgrade Program (Detail 5.2.8).

UNR 90-81-21:

Corrosion was visible on portions of both containment liner Rust was visible through gaps, on retention studs, and on the floor at the liner bas (Detail 5.2.1)

UNR 90-81-22:

The team identified the use of teflon tape within contain-men (Detail 5.2.1)

UNR 90-81-23:

The team identified examples of misapplication of 10 CFR 50.59 requirement For example, a 10 CFR 50.59 safety evaluation was used to justify the installation of a non-code repai In another case, a required 10 CFR 50.59 safety evaluation was not performed when an eroded containment fan cooling unit was repaired through the use of Belzona 11 R11 meta Additionally, station management displayed an unfamiliarity with 10 CFR 50.59 requirements and Attachment 6 of AP-32, 11 Implementing Procedures Program, 11 contained erroneous information with respect to 10 CFR 50.5 (Detail 5.2.9)