IR 05000461/1999006

Insp Rept 50-461/99-06 on 990217-0407.Violations Noted.Major Areas Inspected:Operations,Maint & Engineering

ML20205S697
Person / Time
Site:	Clinton
Issue date:	04/21/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20205S695	List: IR 05000461/1999006 ML20205S692
References
50-461-99-06, 50-461-99-6, NUDOCS 9904260325
Download: ML20205S697 (34)

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l U.S. NUCLEAR REGULATORY COMMISSION q

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REGION lli l

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l Docket No: 50-461  !

License No: NPF-62 I l

Report No: 50-461/99006(DRP) )

i Licensee: lilinois Power Company Facility: Clinton Power Station Location: Route 54 West Clinton, IL 61727 Dates: February 17 - April 7,1999 Inspectors: T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector C. E. Brown, Resident inspector J. A. Clark, Resident Inspector, Perry Plant M. E. Parker, Senior Reactor Analyst D. H. Coe, PRA Analyst, NRR D. E. Zemel, Illinois Department of Nuclear Safety Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4 Division of Reactor Projects l

9904260325 990421 PDR ADOCK 05000461 G PDR

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EXECUTIVE SUMMARY Clinton Power Station NRC Inspection Report 50-461/99006(DRP)

This inspection included aspects of licensee operations, maintenance and engineering. The report covers a 7-week period of resident inspection.

Operations

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The inspectors identified an example of a previously identified violation for the failure to ensure that the completion of compensatory actions for degraded equipment was documented in the MCR journal.

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The inspectors determined that operations personnel had improved performance in the areas of communications, shift and relief turnovers, Technical Specification and procedure implementation, and the use of peer checks in the MCR (Section 04.1).

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The inspectors identified one non-cited violation with five examples due to the inadequacies in the conduct of MCR activities. The violation examples involved the failure to minimize MCR distractions and loitering; inappropriately conducting training in the at-the-controls area of the MCR; the failure to understand the expected plant response before proceeding with a unit substation bus outage; the failure of a management member to be present for a significant, infrequently performed test or evolution brief; and the failure to monitor MCR panels. These inadequacies demonstrated that operations personnel did not provide adequate oversight to maintain a professional atmosphere in the MCR at all times (Section 04.1).

. The effectiveness of the operations oversight representatives was mixed. Individuals acting as shift mentors frequently observed MCR activities. However, constructive feedback from the management observers was not provided due to the lack of recognition of poor operator performance during various activities (Section 04.1).

. The inspectors concluded that the initial documentation provided to support closure of I

Case Specific Checklist (CSC) Restart Item 11.1, " Establish and Implement Continuing Operator Training Emphasizing Technical Specification Adherence / Knowledge and

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Recognition of Degraded Conditions," was narrowly focused and did not contain the supporting information for the actions the licensee had indicated were taken to resolve this item. Subsequently, operations and training department personnel provided supplemental information to the inspectors to support resolution of each issue associated with this item except those related to work control. Consequently, CSC Restart item II.1 will remain open pending the review of corrective action documentation related to various aspects of the work control process (Section 08.1).

l l . The inspectors determined that the licensee's review of procedures to support CSC l l Restart item 11.3, " Review and Revise Abnormal Operations Sections of Operating j Procedures," was narrowly scoped in that only 3 of 47 procedures were reviewed l following the licensee's determination that a significant number of operating procedures I

required revision prior to restart. Following additional inspector prompting, the hcensee completed the review and revision of the remaining procedures. The inspectors l

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I determined that the licensee had resolved the concerns associated with CSC Restart item 11.3 (Section 08.2).

Maintenance

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The inspectors determined that steps were taken to increase the resources applied to the effectiveness of the Fix-it-Now (FIN) team. However, poor communications of these steps resulted in confusion between operations and FIN team personnel and created an unnecessary distraction in the MCR (Section M1.2).

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The inspectors identified one non-cited violation for the failure to ccnduct adequate

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post-maintenance testing after completing work on air-operated containment isolation valve 1SA-030 (Section M1.3).

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The inspectors identified one non-cited violation for the failure to complete an adequate l safety evaluation prior to revising Procedure 1029.03, " implementation of the Fix-it-Now Process," as required by 10 CFR 50.59 (Section M6.1).

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The inspectors identified one non-cited violation due to the failure to maintain adequate

, FIN team shift coverage without the heavy use of overtime. In addition, the licensee l did not have an effective program for limiting excessive overtime for FIN team

! individuals working on safety-related activities (Section M6.2).

. The inspectors determined that the licensee had resolved the concerns associated with CSC Restart item II.4, " Establish and Implement an Effective Risk Assessment

' Program" (Section M8.1).

. The inspectors determined that the licensee had resolved the concerns associated with CSC Restart Item IV.2, " Provide Reasonable Assurance that Deficiencies Affecting Safety-Related Structures, Systems, and Components Have Been Identified and Corrected" (Section M8.2).

. The inspectors determined that the licensee had resolved the concerns associated with CSC Restart item V.1, " Develop Process to Review Deferrals of Preventive Maintenance items" (Section M8.3).

. The inspectors determined that the licensee had resolved the concerns associated with l CSC Restart item V.2, " Provide Reasonable Assurance that Qualified Materials and j Parts are Installed in Plant Systems" (Section M8.4). l Enaineerina l

. The inspectors observed that testing of the reserve auxiliary transformer static var compensator was well controlled. Potential coordination issues were minimized through the use of effective briefs and just-in-time training (Section E2.1).

. The inspectors determined that the licensee had resolved the concerns associated with CSC Restart item IV.6, " Complete Root Cause Analysis of Recirculation Pump Seal Failures and Develop Field Performance Measures" (Section E8.1).

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Report Details Summary of Plant Status The plant remained shutdown during the inspection period. Major activities included the completion of a Division I outage and static var compensator testing, l. Operations 01 Conduct of Operations 01.1 Review of Compensatory Actions a. Inspection Scope (71707)

The inspectors reviewed the operations department logs to determine if compensatory actions for degraded equipment were completed and documented as required.

b. Observations and Findinas Section 8.2.3 of Procedure 1406.01, " Procedures and Operator Aids," stated that once per shift the B reactor operator (RO) shall verify that compensatory actions have been completed and a main control room (MCR) journal entry shall be made. The inspectors observed that operations personnel had not documented the completion of shift compensatory actions in the MCR journal on February 9 and 11,1999, as required by Procedure 1406.01. The licensee determined that completion of the activities was also not documented on the affected area operator rounds sheets.

The failure to document the completion of shift compensatory actions previously resulted in a violation, for which enforcement discretion was exercised, as described in NRC Inspection Report 50-461/98020 (NCV 50-461/98020-02). Additionally, weaknesses with implementation of compensatory actions were documented in NRC Inspection Report 50-461/98017. This violation constitutes an additional example of NCV 50-461/98020 and is not being cited individually. Further corrective actions for this additional example are expected to be taken in conjunction with corrective actions for NCV 50-461/98020.

c. Conclusions The inspectors identified an example of a previously identified violation for the failure to ensure that the completion of compensatory actions for degraded equipment was documented in the MCR journal, i

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04 Operator Knowledge and Performance 04.1 Continuous Cgntrol Room Observations a. Inspection Scope (71707)  !

, The inspectors conducted 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> of continuous MCR observations. The inspectors l primarily observed operator performance with respect to the key attributes described in NRC Information Notice (IN) 87-21, " Shutdown Order issued Because Licensed Operators Asleep While On Duty."

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b. Observations and Findinas l

The inspectors noted that operator performance had improved in a number of areas j relative to operator performance observed during previous inspection pericds. i Examples of improved performance included:

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Communications: The inspectors observed frequent use of three-part communications within the control room and with field operators.

Technical Specification Usage: The inspectors observed frequent use of and reference to the Technical Specifications (TSs) by on-shift operations personnel. For example, on March 18, the control room supervisor (CRS)

determined through a review of the TSs, that the emergency core cooling mode ;

of the residual heat removal (RHR) system Train A would be inoperable during '

testing of a feedwater check valve modification. The impact on the TSs had not ,

l been identified previously through the planning and scheduling process. l l

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Shift Relief and Turnovers: Shift turnovers included discussions of the l appropriate information regarding plant status and ongoing activities. Relief l turnovers included discussions of changes in plant status that occurred during the shift.

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Procedure Use: The inspectors determined that all observed activities were conducted with the correct procedure in active use. Procedures were reviewed prior to the manipulation of plant equipment.

Peer Checks: The inspectors determined that peer checks were of high

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quality. In most instances, a discussion of the expected plant response, specific l indications that should be observed, and annunciators impacted was conducted l between the operator completing the evolution and the individual providing the l

peer check. The involved operator and peer checker concurred on switch manipulations before the manipulation of any component was initiated from the MCR. The inspectors observed that through the peer check process, operators identified potential incorrect switch operations and typically ensured that the expected plant response was understood prior to proceeding with the switch manipulation.

Annunciator Response and Evaluation of Abnonnal Conditions: The inspectors determined that the annunciator response procedures were typically l 5 l

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l referenced in response to plant alarms. Abnormalindications received the I appropriate level of evaluation by the operating crew. In most instances, operations personnel were aware of the reasons for pre-existing alarms and annunciators.

Two noteworthy exceptions were noted by the inspectors. First, on March 17, J

the operating crew started condensate pump D and received an unexpected '

annunciator for low pressure feedwater heater 58. The CRS initially ignored the annunciator because he considered it to be of low importance due to the current plant condition. When questioned by the inspectors, the CRS acknowledged that he had not responded appropriately to the annunciator. Second, on March 19, the CRS allowed operators to defer acknowledging annunciators {

during reserve auxiliary transformer (RAT) testing even though no annunciators were expected as a result of the testing. This practice is referred to as the transient annunciator response mode by the licensee. While invoking this practice the operating crew delayed reviewing annunciators involving the loose parts monitor and the steam jet air ejectors, which were not associated with the RAT testing.

Log Keeping: The inspectors determined that the MCR journal accurately reflected the activities conducted during the shift.

The inspectors identified several concerns regarding the operators maintaining a professional atmosphere in the MCR consistent with the guidance in IN 87-21. Four of the more significant concerns identified involved: (1) not controlling MCR access to persons on official business only and prohibiting loitering in the MCR area, (2) licensed operators being inattentive to the instrumentation and controls located within the MCR, (3) licensed operators and operating supervisors being unaware of and not responsible for the plant status at all times, and (4) conducting plant related technical and administrative control room business at a location and in such a manner that licensed control room operator attentiveness and the professional atmosphere was potentially compromised. Examples of some of the issues identified during the 60-hour observation include:

Performance of Management Observer and Shift Mentor: The management observer was not present during the backshift on March 17 and 18. Aspects of operator performance in connection with activities involving testing of alarm panels during a change in reactor vessel level, conducting training in the MCR, an infrequently performed test and evolution brief for RAT testing, operator response to an unexpected plant event during a loss of unit substation bus O, and difficulties with restoration of unit substation bus C were either not recognized or not considered significant by the management observer. Based on the lack of recognition of these performance issues, the inspectors l

determined that the management observer had minimal impact on crew performance.

The inspectors noted that most of the shift mentors frequently observed MCR activities. During their observations of MCR activities, the mentors were expected to brief the shift manager on crew performance in lieu of providing j 6 I

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i direct feedback to the operating crew. Consequently, the inspectors were not able to assess the effectiveness of the shift mentor program. Following the inspectors communicating to plant management the results of their MCR observations, the licensee stated that the management observer program would be temporarily suspended due to delays in the scheduled restart of the facility and to provide additional training and expectations to the personne! assigned to monitor MCR activities. In addition, the licensee stated that changes to the shift mentor program would be made to allow the mentors to provide direct feedback to the operating crew as well as the shift manager.

l Main Control Room Atmosphere: Between March 17 and 19, the inspectors noted that frequent meetings were conducted adjacent to the at-the-controls l

area of the MCR and consequently, these meetings were distracting to the 1 operating crew. For example, at 1:00 a.m. and 1:00 p.m., the licensee l l conducted a work control meeting in the MCR adjacent to the at-the-controls area. During RAT testing, engineering, operations, and management personnel conducted frequent discussions adjacent to the at-the-controls area. While waiting for RAT testing to continue, licensee personnel frequently loitered and I

held discussions not relevant to plant operations adjacent to the at-the-controls area. Personnel waiting to discuss issues with either the CRS or B RO would frequently loiter in the MCR adjacent to the at-the-controls area.

Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A," Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide (RG) 1.33, " Quality l Assurance Program Requirements," Revision 2, February 1978. Section 1 of l Appendix A to RG 1.33 recommends administrative procedures covering authorities and responsibilities for safe operation and shift and relief turnover. j Section 8.2, " Main Control Room Access," of Procedure 401.03, " Control Room i Professionalism," specifies, in part, that it is essential that activities in the MCR be performed in an orderly and professional manner such that there is no )

interference with operators performing their assigned tasks. Additionally, the

! shift manager shall ensure that noise and distractions are held to a minimum.

The inspectors determined that the failure to ensure that noise and distractions in the MCR were held to a minimum was a violation of TS 5.4.1.a. However, ;

this Severity Level IV Violation is being treated as a Non-Cited Violation, i consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 1-99-03-376 (NCV 50-461/99006-01).

Section 8.6, " Shift Briefing," of Procedure 1401.04, " Shift Turnover and Relief,"

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should be limited to information pertinent to plant operations (e.g., plant status, planned shift activities, night orders, etc). However, following the shift briefing on March 19,1999, the shift manager requested that personnel remain in and adjacent to the at-the-controls area of the MCR so that training could be provided on a planned revision to the shutdown cooling procedure. The inspectors observed that the training lasted for approximately 12 minutes and that a training attendance sheet was distributed during and following the

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session. The inspectors identified that the operations support manager, management observer, shift mentor, shift manager, SROs, ROs, and non-licensed operators did not challenge the appropriateness of conducting training in the at-the-controls area of the MCR. The inspectors determined that conducting training in the at-the-controls area of the MCR was a distraction to operations personnel and is an additional example of a violation of TS 5.4.1.a.

Following the training session, a non-licensed operator stated that he had questions regarding the proposed changes to the shutdown cooling procedure l but did not ask them because the shift briefing had already been too long. The l non-licensed uperator stated that he would question the instructor at a later i

time. The inspectors determined that the response by the non-licensed operator further reinforced the inappropriateness of conducting training in the -

at-the-controls area.

Additional concerns with the control room atmosphere included a control and

! instrumentation technician entering the at-the-controls area of the MCR without

! permission from the operating crew and an oncoming CRS distracting the A RO

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from conducting his duties during the de-energization and recovery of unit j substation bus O.

l Control Room Supervisor Oversight: On March 19, operations personnel

held a briefing for the de-energization of unit substation buses C and O. During

! the briefing, an operator stated that unexpected annunciators and equipment responses were expected since not all of the known responses were documented in the bus outage checklist. The CRS stated that operations personnel were to be especially watchful for unexpected indications, in i addition, the CRS directed other operations personnel to document any l unexpected system / equipment responses or indications so that the bus outage l checklist could be revised prior to its next use.

l l The inspectors observed that the operator's comments regarding unexpected l indications or system / equipment responses were not challenged by the shift l manager, shift technical advisor, work control supervisor, management l observer, shift mentor, or the ROs. In spite of not knowing the expected plant L response, the operating crew decided it was safe to proceed with the unit

! substation de-energization immediately after de-energizing the unit substation, the operating control rod drive pump tripped and portions of the neutron ,

monitoring and vessel level indications were lost.  ;

i l Section 8.1.3, " Nuclear Safety," of Procedure 1401.01, " Operating Philosophy," ;

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requires that each person involved in an activity / task be responsible to assure that the scope of a task or activity, its overall objective, and potential problems are known and understood. In addition, operations personnel are not to proceed with a task or activity with any doubt about what the expected outcome ,

or possible consequences will be. The failure of operations personnel to assure that potential problems were known and understood prior to proceeding with a unit substation bus outage, and the decision to proceed without knowing the expected outcome or possible consequences, is an additional example of a violation of TS 5.4.1.a.

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Additional weaknesses in the oversight of MCR activities involved: (1) the completion of peer checks by the CRS when additional personnel were available to perform the checks, (2) the CRS and ROs not being aware that personnel had been dispatched to respond to a water treatment annunciator, and (3) allowing an assistant test director for RAT testing to manipulate the plant computer as well as to respond to MCR annunciators.

Control Room Briefs for Evolutions: Step 8.2 of Procedure 1401.11,

" Planning and Controlling Evolutions," specifies that the plant manager, the director-operations, the engineering manager, or the maintenance manager shall be notified of pre-job briefings associated with significant, infrequently performed tasks or evolutions, before the briefings are conducted.

Step 8.3 of Procedure 1401.11 states that senior management will determine if a senior manager is required to be present at the briefing. Step 8.3 further states that if a senior manager is required to attend the briefing, that manager will be one of the senior managers specified in Step 8.2 or the work management manager, the director-plant engineering.

On March 17, the inspectors observed that one of the senior management representatives specified in Step 8.3 of Procedure 1401.11 was not present during the briefing for RAT testing, a significant, infrequently performed test or evolution. The inspectors observed that the manager for the degraded voltage modification project was in attendance; however, his attendance did not satisfy the requirements of Step 8.3. The inspectors determined that the failure to comply with the management member requirements for conducting a significant, infrequently performed task or evolution brief is an additional example of a violation of TS 5.4.1.a. In addition, the inspectors determined that Procedure 1401.11 did not require the management member to be present during the actual task or evolution and that the briefing checklist did not specify who the required management members were for a significant, infrequently performed task or evolution briefing.

Step 8.7,4 of Procedure 1401.11 specifies that pre-job briefings should be interactive with the involved workers providing much of the information based on their experience or obtained from a pre-job walkdown. The experience and training of workers should be used during the briefing. The inspectors observed that briefings and turnovers were not interactive, but did convey all of the necessary information.

Control Roorn Panel Walkdowns: The inspectors determined that MCR panel walkdowns were infrequent. Walkdowns were typically conducted immediately prior to and during shift turnover. During the remainder of the shift, only the P-680 panelindications were assessed by the A RO. The remaining control room back panels, engineered safety feature panels, and balance-of-plant panels were not periodically monitored. For example, on March 17, between 11:00 a.m. and 5 p.m., only the P-680 panel indications were assessed.

Section 8.3, " Control Room Supervisor," of Procedure 1401.02, " Operations Department Organization, Duties, and Responsibilities," specifies that the CRS

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I f monitors indications, annunciators, and recorders in order to detect unusual or l abnormal trends and initiates appropriate and timely corrective action to correct I

l or mitigate the condition. Section 8.6, " Reactor Operator," of l Procedure 1401.02, specifies that the ROs continuously monitor plant systems ( and instrumentation to assure the plant is functioning within design parameters. I The inspectors determined that the failure of the CRS to monitor control room I panels and the B RO to continuously monitor MCR panels and instrumentation was an additional example of a violation of TS 5.4.1.a involving the conduct of operations.

Two days before the inspectors began monitoring MCR activities on a continuous basis, the inspectors questioned operations personnel to determine why annunciators associated with the unavailability of three Division I systems were illuminated if all Division i equipment was operable. The B RO and the l CRS initiated a panel walkdown and determined that the annunciators were lit because operations personnel had forgotten to return the out-of-service j switches for the three systems back to the " normal" position prior to declaring the systems operable for all modes. The inspectors considered this a l weaknas since the annunciators were not recognized by operations personnel for apprcximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

On March 16, during a MCR panel walkdown, the inspectors observed that the Division I control room differential pressure indicator had failed. The inspectors questioned the MCR operators about the indicator and determined that the on-shift operators were not aware of the reason for the failed indicator. After further review, operations personnel determined that the indicator had failed downscale during implementation of a safety tagout which resulted in a fuse for l

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the instrumentation circuitry being removed. However, the safety tagging group had not caution tagged the indication prior to removing the fuse.

On March 18, the inspectors determined that the indication for shutdown service l water flow to the RHR heat exchanger was pegged low. Operations personnel had not previously observed the discrepancy and initiated an action request to repair the deficiency.

l Following the 60-hour observation and the loss of the unit substation events, the licensee initiated CR 1-99-03-376, suspended all activities involving bus outages, suspended on-shift activities until a critique of the operators' performance could be evaluated, and initiated a site-wide stand down to discuss the need to maintain an operationally centered focus on plant activities. During control room observations subsequent to these actions, the inspectors determined that the actions were initially effective in improving performance relative to the issues previously described in this section.

c. Conclusions The inspectors determined that operations personnel had improved performance in the ereas of communications, shift and relief turnovers, TS and procedure implementation, and the use of peer checks.

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The effectiveness of the operations oversi0ht representatives was mixed. Individuals acting as shift mentors frequemly observed MCR activities. However, constructive feedback from the management observers was not provided due to the lack of recognition of poor operator performance during various activities.

i Five examples of a violation involving various inadequacies in the conduct of MCR activities were identified. The examples involved the failure to minimize MCR distractions and loitering, inappropriately conducting training in the at-the-controls area of the MCR, the failure to understand the expected plant response before proceeding with a unit substation bus outage, the failure of a management member to be present for a significant, infrequently performed test or evolution brief, and the failure to monitor MCR panels. As a result of the observations, the inspectors concluded that operations personnel did not provide the necessary amount of oversight to maintain a professional atmosphere in the MCR room at all times.

08 Miscellaneous Operations issues 08.1 (Open) Case Soecific Checklist Item II.1. " Establish and implement Continuina Operator Trainina Emphasizina Technical Soecification Adherence /Knowledae and Recoanition of Dearaded Conditions."

The licensee submitted documentation to the NRC pertaining to the resolution of Case Specific Checklist (CSC) Restart item 11.1 on March 8,1999. The inspectors initial assessment of the documentation was that it was narrowly focused and did not contain the supporting information for the actions the licensee had indicated were taken to resolve this item. Specific weaknesses in closure package documentation were discussed with licensee representatives between March 25 and 29,1999.

Subsequently, operations and training department personnel provided supplemental information to the inspectors on April 1 and 2,1999. The licensee took the following actions to resolve this item:

Implementation of tracking system for control of Technical Specifications NRC Inspection Report 50-461/97025 documented that the licensee's means of tracking CRs and maintenance activities identified as mode restraints was inconsistent and cumbersome. In response to this issue, the licensee developed and implemented a computerized operability restraint database to track the status of degraded or inoperable systems, subsystems, or components. The database was also used to j track Limiting Condition for Operation (LCO) actions, Operational Requirements Manual (ORM) actions, Offsite Dose Calculation Manual (ODCM) remedial l requirements, and the completion of safety function determinations.

The inspectors reviewed the operability restraint database and completed two I verification activities. In each case, all CRs and maintenance activities identified as I mode restraints were included in the database.  :

i Completion of Technical Specification training Inspection Report 50-461/97025 described an adverse trend in the operations department's ability to properly use and implement TSs. In response to this issue, the

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licensee initiated CR 1-98-01-059, completed a root cause analysis, and developed corrective actions to resolve the condition described in the CR. l In September 1998, the inspectors reviewed the licensee's actions to resolve the issues t described in CR 1-98-01-159 and determined that the licensee's corrective actions were not fully effective in improving TS usage and implementation. Specifically, the licensee and the inspectors identified that operations personnel had not properly implemented TSs approximately 15 times between May 1 and August 20,1998. In response to this issue, the licensee initiated CR 1-98-08-296, completed another root cause analysis, and developed additional corrective actions to improve the usage and implementation of TSs by operations personnel. The corrective actions included:

(1) the development of a TS, ORM, and ODCM training program which used l scenario-based instruction, (2) the administering of a TS examination to all licensed I operators and shift engineers, and (3) the use of simulator scenarios which required l operations personnel to evaluate TS, ORM, and ODCM requirements.

The adequacy of simulator scenarios was documented in inspection Report 50-461/98029. The inspectors reviewed several lesson plans and determined that the plans addressed multiple and inter-related systems and various operating conditions. From a review of the TS exam results, the inspectors noted that 9 of 55 individuals did not initially pass the exam. In each case, the licensee successfully remediated the individuals or removed the individuals from licensed duty.

l The inspectors discussed the exam results with training personnel to identify any common causes for the failures. Training personnelinformed the inspectors that based on an exam question analysis, thay had identified several areas that needed additional emphasis including: (1) the implementation of TS-required completion times, (2) the identification of system logic to determine TS applicability, and (3) the use of Procedure 1405.03, " Loss of Safety Function." The licensee planned to address these areas as part of the licensed operator requalification training program.

Revision to surveillance program to ensure that TS requirements are met and scheduled in late 1997, the Special Evaluation Team (SET) identified that portions of surveillance tests were either not completed or were completed late. The inspectors reviewed the SET's concern as part of their inspection activities associated with NRC Inspection Report 50-461/98014 and identified that 44 percent of all monthly and quarterly surveillance tests were completed within the 25 percent grace period and that 11 overdue TS surveillance requirements were not included in a weekly surveillance test report.

In response to this issue, the licensee initiated CR 1-98-07-184. The inspectors were unable to review the effectiveness of all corrective actions since a copy of the CR was

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not included in the closure package for CSC Restart Item II.1. However, the inspectors l reviewed a list of mode 4 and 5 surveillances and determined that the licensee had

! improved upon the timely completion of surveillance testing. Of the 900 tests reviewed, only 16 percent were completed within the 25 percent grace period. The inspectors considered this acceptable since several surveillance tests had to be rescheduled due to plant conditions or schedule delays. The inspectors also compared the surveillance

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coordinator's list of overdue surveillances to the surveillance test report. No deficiencies were identified.

Ability to recognize degraded plant conditions and non-conforming conditions l

During late 1997 and early 1998, the inspectors documented numerous examples of operations personnel failing to recognize degraded and non-conforming plant l

l conditions. In response to this issue, the licensee developed 32 new simulator '

scenarios which emphasized the recognition of multiple degraded conditions. In addition, shift mentors have quizzed each operations crew regarding the reason for and status of various MCR deficiencies, annunciators, and tagouts.

Due to the inspectors' concern regarding the frequency of MCR panel walkdowns I (see Section 04.1), the licensee has taken action to ensure that panel walkdowns are completed in a deliberate manner. While the completion of panel walkdowns has l improved over the last two weeks, the long-term effectiveness of the licensee's corrective actions remains in question. In addition, the completion of panel walkdowns by the B RO remained a challenge due to the large number of activities taking place in the MCR.

The licensee planned to implement additional actions to improve panel walkdowns and the operators' ability to recognize degraded conditions following restart. Items being considered included the development of a static simulator examination to be given during the 1999 licensed operator requalification training cycle.

Adequacy of the work contro: program The licensee had not completed root cause analyses, apparent cause analyses, and corrective action plans associated with various aspects of the work control process.

The analyses involved work coordination, Fix-it-Now team utilization, and equipment status control. As a result, Case Specific Checklist item 11.1 will remain open pending the inspectors' review of the adequacy of the analyses and planned corrective actions associated with the work control issues.

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08.2 (Closed) Case Specific Checklist Restart item ll 3. " Review and Revise Abnormal Operations Sections of Operations Procedures."

The licensee submitted the closure package for CSC Restart item 11.3, " Review and Revise Abnormal Operations Sections of Operations Procedures," to the NRC on March 1,1999. The licensee initially conducted a narrowly focused review of procedure issues in that the initial assessment was limited to a review of the abnormal l

sections of operating procedures. The narrow review was conducted in spite of repeated meetings between the NRC inspectors and the licensee to discuss concerns

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with the quality of off-normal procedures and the procedure backlog.

i The licensee selected approximately 48 of the 95 operating procedures for an in-depth l

review by operations personnel. Of the 48 procedures reviewed,28 (58 percent)

required revision to incorporate more conservative guidance or technical changes. The inspectors questioned operations personnel to determine if the remaining operations procedures had been reviewed c;ven the large percentage of procedures which

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l required revision following the initial review. The licensee stated that it had not expanded the scope of the procedure review but committed to cond%t a review of the remaining 47 system operating procedures prior to restart. The licensee reiterated this l commitment at a pub!ic NRC 0350 Pestart Meeting on March 18,1999. j l .

On March 31, the inspectors discussed the results of the licensee's review of the remaining 47 system operating procedures with operations support personnel. The inspectors determined that the licensee had only reviewed 3 of the 47 procedures and that no assessment activity had been planned to review the remaining 44 procedures l before or after restart. When questioned by the inspectors, the director of operations l restated that the commitment was to complete a page-by-page review of the remaining j 47 procedures and that each of the procedures would be reviewed before restart. The inspectors verified that operations personnel had completed the review and revised the remaining procedures, as appropriate. l l

In response to NRC identified concerns regarding the extent of the procedure backlog, described in NRC Inspection Report 50-461/99002, the licensee expanded the scope of )

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CSC Restart item 11.3 to include a full review of all comment control forms (CCFs) and CR corrective actions to ensure technical issues impacting the procedures were addressed prior to restart. Of the approximately 2000 CCFs reviewed,310 CCFs contained technical issues affecting 160 procedures, which consequently required these procedures to be revised prior to restart or the next use of the procedure.

Additionally, the licensee changed the process by which changes and revisions to plant procedures were initiated to ensure technical issues were promptly addressed.

The inspectors questioned the licensee regarding procedure changes made using the temporary procedure deviation (TPD) or the procedure deviation for revision (PDR)

processes. In response to the inspectors' questions, the licensee initiated potential adverse trend CR 1-99-03-039. During the CR review, the licensee determined that the TPD/PDR process was changed in April 1997 to allow procedure revisions to be made l easier in order to prevent personnel from " working around" procedures. In addition, the

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licensee determined that 25 (4 percent) of the TPDs/PDRs were disapproved for technical reasons in the last 6 months. Although the 25 TPDs/PDRs were viewed as adequate by the cognizant operations shift manager, the licensee determined that the operations shift manager could not have been expected to know the change was technically incorrect. In response to this issue, the licensee recommended changes to the TPD/PDR program which included: (1) improved trending of TPD/PDR disapprovals, (2) evaluating the TPD/PDR for technical adequacy prior to shift manager i approval when practical, (3) increased questioning for proposed changes involving setpoints, system operating procedure valve and breaker lineups, and test procedures, and (4) briefing shift managers and management staff members on recommended changes to the TPD/PDR processes.

l The licensee conducted a review of system operating procedures to ensure that safety l evaluations existed for proceduralized temporary modifications (TM). Following the

' licensee's review, either proceduralized TMs were removed from plant procedures, the affected procedure was revised to require implementation of the TM process before installing the TM, or a safety evaluation was completed for the TM.

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! The licensee's Plan-For-Excellence reviews involving the quality of procedures included l assessments and associated revisions to integrated startup procedures, emergency operating procedures, annunciator response procedures, and surveillance test procedures. In addition, due to assessment results regarding operating procedures which may not maintain the plant configuration consistent with the design basis, the licensee initiated CR 1-98-11-006, and commenced a review of procedures associated with 15 systems. On March 31, the licensee stated that a review of procedures for all l safety-related systems would be completed by August 1,1999.

l The inspectors determined that the licensee initially implemented a narrowly scoped 3

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review of issues regarding the technical adequacy of procedures. Following an assessment by the inspectors, the licensee sufficiently expanded the scope of procedure reviews to provide reasonable assurance that plant procedures were sufficiently reviewed and revised such that they contained technically correct information.

II. Maintenance

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M1 Conduct of Maintenance

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M1.1 General Comments (61726 and 62707)

Portions of the following maintenance and surveillance activities were observed or ( reviewed by the inspectors:

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Procedure 2825.18 Reserve Auxiliary Transformer Static Var Compensator j l Test 4

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AR F02416 Valve 1SA-030 Maintenance The inspectors determined that observed activities were completed with the procedure l

present and in active use. Specific observations pertaining to these maintenance and j surveillance activities are discussed in Sections M1.2, M1.3, and E2.1.

l M1.2 Fix-It-Now Team Process l

l a. Insoection Scope (62707)

l The inspectors followed the guidance in IP 62707, in assessing the Fix-It-Now (FIN)

l team's activities. The inspectors assessed FIN team daily activities, the flowpath of work activities, and FIN team interfaces with other plant organizations. The inspectors also conducted interviews with various FIN team members and operations personnel.

b. Observations and Findinas The inspectors determined that the FIN team was effective with 15 to 20 maintenance activities accomplished on a daily basis. The inspectors identified that several personnel reassignments and conducting work activities in accordance with a recent revision to Procedure 1029.03, " Implementation of FIN Process," had increased the l 15

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capabilities of the FIN team. The personnel changes included providing the FIN team with its own director, providing additional supervisors, and the addition of licensed and non-licensed operators to the team. The change to Procedure 1029.03 permitted the 1 FIN team to work on safety-related, environmentally qualified, and fire protection I equipment and also instituted a new FIN team safety tagging process. While these steps were effective in increasing FIN team productivity, the inspectors observed some problems with the FIN team process. The problems included a failure to perform a safety evaluation for the procedure change (see Section M6.1), excessive use of overtime (see Section M6.2), and peripheral communications weaknesses.

Through discussions with FIN team and operations personnel, the inspectors learned that the primary criteria for assigning an activity to the FIN team was whether or not the activity could be expected to be completed in approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The personnel also explained that the FIN team process was streamlined regarding job review, package development, work approvals, and safety tagging to ensure that the team was efficient. Efficiencies were further enhanced by allowing FIN team members to complete impact reviews and safety tagouts. A separate FIN team activity schedule was also developed.

The inspectors determined that operations personnel did not fully understand the process or a.opreciate the ' significance of some of the recent FIN team procedure changes. An example of this occurred on March 17, when the inspectors questioned the on-shift CRS about FIN team activities scheduled for the day. Although it was approximately 9:00 a.m., and the briefing on daily maintenance activities had been conducted within the past two hours, the CRS could not recall what FIN team activities were planned for that day. The CRS also could not produce the printed list of scheduled FIN team activities for the inspectors, nor could he explain the process for safety evaluations and contingency plans for FIN work on safety-related equipment.

Another interface problem involved maintenance on the auxiliary building ventilation system. Fix-it-Now team personnel commenced maintenance activities on the system even though the task was not annotated on the FIN team activity schedule and the work control supervisor had not been notified of the activity.

Through subsequent discussions with operations personnel, the inspectors determined that operations personnel did not fully appreciate the safety significance of FIN team work. Some operations personnel stated that they still viewed FIN team work as minor.

In addition, operations personnel were not trained on the FIN team safety tagging ]

process. The lack of training resulted in confusion between operations and FIN team i personnel when hanging safety tags in the at-the-controls area of the MCR and created an unnecessary distraction for the MCR operators.

The inspectors discussed their observations with the maintenance manager and the l FIN team director. The maintenance manager and FIN team director stated that i additional training was planned for operations personnel on the new FIN team processes including work control and safety tagging. Maintenance management also l stated that they would evaluate the use of a single daily maintenance activity list to l ensure FIN team activities were considered at the same significance level as other ,

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I e c. Conclusions The inspectors concluded that the licensee took steps to increase the resources applied to and improve the effectiveness of the FIN team. However, these steps were not well communicated to all affected personnel. This resulted in confusion between operations and FIN team personnel and resulted in an unnecessary distraction for the MCR operators.

M1.3 Failure to Conduct Acoropriate Post-Maintenance Testina a. Inspection Scope (62707)

The inspectors reviewed the completed documentation associated with maintenance on air-operated containment isolation valve 1SA-30.

b. Observations and Findinas On January 16,1999, FIN team personnel completed maintenance on containment isolation valve 1SA-030 in accordance with action request F02416. The maintenance activity involved adjusting the valve actuator spring tension to achieve the desired stroke time. Post-maintenance testing for this activity involved completing a stroke time test in accordance with Procedure 9061.03, " Containment /Drywell isolation Valve

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Three-Month Operability." Followhg completion of the stroke time test, operations personnel returned valve 1SA 030 to an operable status.

I The inspectors determined that the adjustment of the actuator spring tension impacted the seating characteristics of the valve and that a localleak rate test should have been completed prior to declaring the valve operable. Engineering personnel agreed with the inspectors assessment and initiated CR 1-99-02-380. In addition, operations personnel declared valve 1SA-030 inoperable and added the local leak rate test to the mode 2 restraint list.

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Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A, " Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of RG 1.33, " Quality Assurance Program Requirements," Revision 2, February 1978. Section 9 of Appendix A to RG 1.33 recommends procedures for performing maintenance activities. Section 8.6," Post-Maintenance Testing," of Procedure 1501.04, " Air-Operated Valve Program," specifies, " .. valves typically have their actuators sized with certain operational requirements such as seat loads and stem !

friction loads. To change these values may affect the operability of the valve. To this )

end, the following post-maintenance testing requirements are established: air-operated valves will norme!!y have a diagnostic flow test completed following any maintenance."

l Additionally, Appendix B," Equipment and Piping Post-Maintenance Testing (PMT)

Guide," of Procedure 1014.05, " Preparation of Post-Maintenance Testing," specifies that for air-operated valve repair or replacement, the following PMTs are required / recommended: full stroke exercise check, seat leakage test, stroke time test, automatic function test, position indication test, control valve loop alignment, packing leakage, and positioner converter calibration.

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The inspectors determined that the requirements for post-maintenance testing of air-operated valves, as specified in Procedure 1014.05, did not include the requirement for completing diagnostic flow testing as specified in Procedure 1501.04. Additionally, the inspectors determined that the failure to complete localleak rate testing following maintenance on air-operated containment isolation valve 1SA-030 is a violation of TS 5.4.1.a. However, this Severity Level IV Violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 1-99-02-380 (NCV 50-461/99006-02).

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c. Conclusions The inspectors identified one non-cited violation for the failure to conduct adequate post-maintenance testing following maintenance on air-operated containment isolation valve 1SA-030.

M6 Maintenance Organization and Administration M6.1 Incorooration of FIN Team Procedure Chanaes a. Inspection Scope (62701)

The inspectors followed the guidance in IP 62707 to assess the licensee's administration of FIN team activities. The inspectors reviewed the current version of Procedure 1029.03, " Implementation of Fix It Now (FIN) Process," the previous procedure revision, and the associated safety evaluation screening form to ensure the procedure revision was processed in accordance with 10 CFR 50.59.

b. Observations and Findinas l The inspectors reviewed Revision 3 of Procedure 1029.03 and determined that the new

, revision permitted work on safety-related, environmentally qualified, Technical l Specification-related, and fire protection-related equipment. Work on this type of equipment had been previously excluded from the FIN team. The inspectors also

, determined that the procedure revision incorporated a new organizational structure, l new reporting and communication channels for maintenance and operations personnel l associated with FIN team work, and new administrative guidelines for plant I

configuration control in the form of a separate safety tagging procedure for FIN team work.

l The inspectors determined that although numerous changes were made to the FIN l team procedure's scope, the licensee did not complete an adequate 10 CFR 50.59

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safety evaluation. Specifically, the inspectors identified that while the FIN team procedure was not listed in the Updated Safety Analysis Report (USAR), the procedure change affected maintenance activity administration, work control processes, and maintenance organizations and reporting structures that were described in several USAR sections including: Section 6.3.2.8 (Manual Actions), Section 13.1.2.1.3 (Plant Maintenance), Section 13.1.2.1.4 (Work Management) and Figure 13.1-1, "Clinton Power Station Organization." The inspectors also determined that the USAR was not changed to reflect the new FIN team relationships and responsibilities.

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l Part 50.59 to 10 CFR states that the licensee shall maintain records of changes in procedures to the extent that these changes constitute changes to procedures as described in the safety analysis report. These records must include a written safety evaluation which provides the bases for the determination that the change, does not involve an unreviewed safety question. Contrary to this requirement of 10 CFR Part 50.59, the licensee failed to complete an adequate safety evaluation for Revision 3 to Procedure 1029.03, which affected procedures described in the safety analysis report. This failure to perform an adequate safety evaluation in accordance with 10 CFR Part 50.59 ir considered a violation of NRC requirements. However, this Severity Level IV Violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's i corrective action program as CR 1-99-03-275. (NCV 50-461/99006-03).

c. Conclusions One non-cited violation was identified for the failure to complete an adequate safety evaluation prior to revising Procedure 1029.03, " Implementation of Fix it Now Process,"

as required by 10 CFR Part 50.59. Although this procedure was not singularly listed in the USAR, the changes implemented by the procedure affected a broad scope of maintenance control activities that were described in the USAR.

M6.2 Fix-It-Now Team Overtime Use a. Inspection Scope (62707)

The inspectors reviewed the guidance provided in Procedure 1001.10, " Control of Working Hours," and Technical Specification 5.2.2.e to assess overtime use by FIN ,

team personnel. l b. Observations and Findinas On March 16,1999, the inspectors discussed r'IN team processes with the FIN team director. One of the issues discussed was the high number of personnel (43) assigned to the FIN team and the high number of jobs completed since the first of the year (1070). The inspectors asked the FIN team director for information regarding work schedules for FIN team members, including the use of overtime. The inspectors l reviewed the information provided and determined that most FIN team members had been working a significant amount of overtime for the past several months.

The licensee's administrative overtime limits are for individuals not to work in excess of 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,24 hours2.777778e-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, and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7 day period. On March 17, the inspectors received specific information on the number of hours worked by 19 FIN team members who were involved with safety-related activities since the beginning of the year. The inspectors determined that these individuals had averaged 62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br /> of work each week since the beginning of the year. One FIN team member had worked every day since the beginning of the year and, while he exceeded the administrative limit of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per week only once, had averaged 73.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of work per week. The required approval for exceeding the administrative limit was

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obtained. However, the inspectors noted that maintenance management was only

} concerned with maintaining the total hours worked to less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per week and i

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that a program to review or limit individuals' overtime if the hours worked were less than 72 per week did not exist.

l The inspectors discussed with maintenance management recent FIN team human performance errors.- The inspectors asked management if an analysis had been i completed to determine if there was a corollary between the use of overtime and the l

occurrence of errors. Maintenance management informed the inspectors that there

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had not been an analysis, but that they would complete one. The inspectors discussed I human performance errors and overtime with the FIN team director. The FIN team

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director stated that while no specific link had been established between these two

- issues, a link could not be excluded due to the continuously high overtime use by the FIN team.

l l Technical Specification 5.2.2.e states, in part, that administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform l safety-related functions. The TS further states that adequate shift coverage shall be l maintained without routine heavy use of overtime, and that controls shall be included in the governing procedures such that individual overtime shall be reviewed monthly by l the plant manager, or his designee, to ensure that excessive hours have not been assigned. In addition to these requirements, the TS also contains requirements that may be used on a temporary basis, for specific unusual circumstances. However, these additional requirements did not apply in this case.

, Procedure 1001.10 implements the requirements in TS 5.2.2.e. and specifies that an l individual should not be permitted to work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period excluding shift turnover time. In addition, Step 6.7 of Procedure 1001.10 states that all site departments shall submit a monthly report of overtime deviations to their respective

, manager with copy to the Manager-Clinton Power Station for their review to ensure that I

excessive hours have not been assigned on a routine basis.

l l Fix-it-Now team personnel tasked with performing safety-related functions during the l period of January 1 through March 14,1999, were routinely assigned excessive l

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overtime. Although the required monthly reports were submitted for the FIN team, no administrative controls were implemented for controlling working hours between 40 and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per week or for ensuring that individuals were not assigned excessive overtime. In fact, excessive hours had been assigned to FIN team members on a

routine basis. The failure to administratively control the overtime of individuals such that excessive hours were not assigned to individuals working on safety-related activities is considered a violation of TS 5.2.2.e. However, this Severity Level IV Violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 1-99-04-063 (NCV 50-461/99006-04).

I c. Conclusions One non-cited violation was identified due to the licensee's failure to maintain adequate FIN team shift coverage without the heavy use of overtime. In addition, the licensee did not have an effective program for limiting excessive overtime for FIN team l individuals working on safety-related activities.

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l M8 Miscellaneous Maintenance issues M8.1 (Closed) Case Soecific Checklist Restart item 11.4. " Establish and imolement an Effective Risk Assessment Proaram."

l As discussed in NRC Inspection Report 50-461/98028, this item remained open pending completion of required training on the on-line risk assessment procedures.

The licensee revised Procedure 1151.12, "On-Line Risk Assessment," and Procedure 1151.12F002, " Contingency Planning," to resolve interaction problems with l Procedure 1151.01, "On-Line Work Management Process." The inspectors reviewed I the revised procedures' contents, training lesson plans and attendance sheets, and interviewed a cross section of the personnel that attended the training. The inspectors determined that the training was adequate and that the licensee's actions were sufficient to support plant restart.

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l M8.2 (Closed) Case Soecific Checklist Restart Item IV.2. " Provide Reasonable Assurance that Deficiencies Affectino Safetv-Related Structures. Systems. and Components (SSCs) have been Identified and Corrected,"

The licensee submitted documentation to the NRC regarding the resolution of CSC Restart item IV.2 on February 5,1999. The inspectors reviewed the licensee's initial closure package and identified several weaknesses which prevented the inspectors from reaching an overall conclusion about the adequacy of the licensee's actions in addressing this restart item. Specific weaknesses included: (1) the failure to recognize that the oil analysis program impacted maintenance rule compliance, and (2) the failure to include the results of various training initiatives in the closure package, e.g., the results of proficiency exams, lesson plans, the status of training waivers, and the results of completed self-assessments. The inspectors identified that the Quality Assurance (QA) department had identified similar weaknesses in the closure package information. Once the additional information was provided, the inspectors determined that the licensee took the following actions to resolve this item:

Completion of System Design and Functional Validation (SDFV) walkdowns in its Demand-for-information concerning the licensee's corrective action program, issued on September 26,1997, the NRC requested that the licensee provide

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reasonable assurance that repetitive hardware issues had been identified and corrected. In response to this concern, the licensee commissioned an SDFV which ensured the functionality of seven safety-related systems. As part of the SDFV review, walkdowns of the selected systems were completed. The inspectors evaluated the

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adequacy of these walkdowns as part of the Safety System Engineering Inspection (SSEI) and will document the results of the SSEl team's assessment in NRC Inspection j Report 50-461/99003.

Completion of preventive maintenance program evaluation

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In January 1998, the licensee organized and staffed the Preventive Maintenance (PM)

Improvement Project. As part of this project, the licensee completed a thorough review of the PM program and vendor manuals to ensure that all required PM activities were incorporated into the PM program. At the conclusion of this inspection period, the

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l licensee had completed reviews for several systems and had prioritized review activities for all other systems, some of which were scheduled to be completed after restart. The inspectors evaluated the results of several completed PM system reviews

! and the licensee's schedule for the remaining reviews of the SSEI team's assessment, and determined they were acceptable.

Develop a procedure to provide guidelines and requirements for the preventive i maintenance program

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l As part of the PM improvement Project, the licensee developed and implemented Procedure 1034.01, " Preventive Maintenance Program," to provide additional guidance to personnel regarding the completion of PM activities / tasks and the administration of the PM program. The inspectors reviewed the new procedure and did not have any concerns.

Concerns with the PM deferral process and the documentation provided to close CSC Restart item V.1, " Develop Process to Review Deferrais of Preventive Maintenance items," were described in NRC inspection Report 50-461/99002. Additional information regarding the PM deferral process is included in Section M8.3 of this report.

Development of a program to identify and resolve repetitive hardware failures Through the efforts of the SDFV initiative, the licensee identified several root causes which potentially contributed to repetitive hardware failures. To fully assess the extent of condition for the root causes, the licensee initiated several other reviews including the Engineering Product Review and the Detailed Design Review. The results of these licensee initiatives were reviewed during the Engineering and Technical Support inspection and the SSEl, and the results of the inspectors' assessment regarding the effectiveness of these review initiatives are discussed in NRC Inspection Reports 50-461/98019 and 99003.

In addition to the SDFV, the engineering department implemented Procedure A.18,

" Conduct of System Engineering," which required each system manager to review the I status of their assigned systems for potential repetitive hardware failures and to provide input for a quarterly system health report. The Material Condition Management Team also developed a quarterly trend report to identify adverse trends in the condition of safety-related and maintenance rule-related equipment. Each of these reports were reviewed by management personnel to ensure that repetitive hardware issues had been identified and resolved.

l Finally, the inspectors accompanied several system managers and operations staff members during system verification activities for the Division l RHR system, the Division ll shutdown service water system, the Division i DC system, and the hig'i pressure core spray system. The system reviews were thorough, procedurally driven, and each of the observed walkdowns was considered acceptable. No significnnt, previously undocumented deficiencies were found during the system walkdowns observed by the inspectors.

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Improvements to maintenance training programs including establishment of continuous training and assessment of the use of training waivers in response to NRC concerns about equipment problems resulting from inadequate maintenance activities the maintenance manager sponsored a review to determine which equipment was or could have been adversely affected by poor maintenance practices. Based on the results of the review, the licensee determined that several factors had contributed to the poor maintenance practices including: (1) a lack of procedural guidance and adherence, (2) a lacx of training, and (3) a failure to evaluate and implement industry recommendations in the maintenance program. Additional reviews were conducted of over 300 maintenance activities and recommendations were made to enhance maintenance program and training effectiveness. Improvements in the conduct of maintenance included revising the Maintenance Performance Handbook to update management expectations for conducting maintenance, revising the

" Conduct of Maintenance Procedure" to incorporate lessons learned, and issuing a troubleshooting procedure for all maintenance disciplines. Improved maintenance practices have been observed by the inspectors as discussed in NRC Inspection Report 50-461/99002.

With respect to maintenance training, all maintenance supervisors attended a training seminar geared toward increasing their involvement in maintenance activities. In addition, extensive training was conducted for all craft personnel to ensure that each individual possessed the knowledge, skills, and abilities needed to conduct effective maintenance. Just-in-time training was instituted to support emergent work activities.

The inspectors reviewed the licensee's performance indicators for maintenance and training effectiveness and determined that both performance indicators have shown a steady improvement in these areas.

The inspectors determined that the training department was responsive to identified weaknesses and that additional training improvement initiatives were instituted.

Improvements included: (1) reducing the number of curriculum review councils (CRCs)

from seven to three, (2) establishing a maintenance training council to oversee improvement initiatives and reinforce management expectations, (3) requiring the CRCs to meet monthly instead of quarterly, (4) instituting the use of training performance indices for each accredited maintenance training program, (5) developing and conducting training on suspect issues, (6) developing a plan for updating and completing the maintenance supervisor qualification card, (7) preparing and administering proficiency examinations and task evaluations for a sampling of workers to determine their baseline knowledge, and (8) interviewing all craft workers to validate their current qualifications. Several workers were disqualified from conducting specific tasks as a result of the interviews and examinations.

The inspectors reviewed the use of training waivers in the maintenance department l

and determined that all of the existing waivers had been reviewed and validated by the licensee. In addition, the inspectors validated that the waivers were based on an f

j accredited training course or other applicable training. Based on the results of a recent QA audit, the licensee identified that some waivers did not have appropriate documentation on file. However, the cognizant supervisor was able to show that appropriate documentation was available.

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NRC assesses effectiveness of corrective actions affecting SSCs The NRC assessed the effectiveness of the licensee's corrective actions which affected safety-related SSCs as. part of the NRC Manual Chapter 40500 inspection and the SSEl. The results of these assessments will be documented in NRC Inspection Reports 50-461/99001 and 99003.

NRC assesses significance of maintenance backlog in March 1999, the inspectors assessed the significance of the maintenance backlog by reviewing 369 plant changes,221 engineering work requests,1594 CRs,2000 maintenance work orders,36 temporary modifications (TMs), and 239 simulator deficiencies, all of which were not scheduled for completion prior to restart. The l

inspectors used engineering judgement and the licensee's current probabilistic risk l assessment (PRA) to categorize each backlog item as having either a high, medium, or '

low potential to increase the probability of failures assumed in the licensee's PRA.

Each category was then given a numerical weighting factor that was multiplied by the ,

number of open backlog items in that category. These category scores were then i summed for each system and multiplied by the PRA system risk importance measures l to obtain a consolidated backlog importance measure for each system. The systems l were then ranked in order of this consolidated importance measure. l I

The inspectors determined that the most likely core damage scenarios were associated with loss-of-c,ffsite-power and station-blackout events. As a result, the inspectors selected backlog items related to eight systems and the loss-of-offsite power initiating event for further review of their potential collective risk significance. The eight systems selected were the auxiliary power / switchyard (AP/SY), emergency diesel generator (all divisions), DC power (DC - t/II/Ill), high pressure core spray, reactor core isolation cooling (RCIC), shutdown service water (SX), emergency diesel generator ventilation (VD), and plant service water (WS) systems. The collection of backlogged items for these systems included 8,32, and 21 items rated as "high," * medium," and " low" significance, respectively, and scheduled to still be open after startup.

Four of the high significance rated items were due to the licensee placing the AP/SY, DC, RCIC, and VD systems in a(1) status under 10 CFR Part 50.65. Of the remaining four high significance rated items, one involved an incomplete evaluation for the inadvertent tripping of a DC battery output breaker and the other three involved pipe wall thinning and higher than expected corrosion rates in service water systems (SX and WS).

Although the loss-of-feedwater initiating event was not initially included in the dominant

! core damage scenarios evaluated by the inspectors (it contributes about 7 percent to core damage frequency per the licensee's PRA), the inspectors added this initiating event to their list due to an incomplete root cause analysis for a feedwater transient event that occurred before the current extended shutdown. in addition, the inspectors i

gave this backlog item a "high" significance rating due to its potential to affect the frequency of the loss-of-feedwater initiating event. The licensee acknowledged the need for thorough root cause analyses and stated that corrective actions for all of the backlog items categorized as "high" significance would be addressed before startto.

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I The inspectors determined that the backlog items reviewed were relatively more significant than other items in the backlog. Each item reviewed had a scheduled work f completion date which was commensurate with its risk significance. Most of the items '

were scheduled for completion by the end of 1999. In addition, the inspectors determined that the principal contributors to risk from the open backlog issues were not significant and should not preclude plant restart.

The inspectors determined that the licensee had provided reasonable assurance that ,

deficiencies affecting safety-related SSCs have been identified and corrected and that '

the licensee's actions to address this CSC Restart item were sufficient to support plant l

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M8.3 (Closed) Case Specific Checklist Restart item V.1. "Develoo Process to Review Deferrals of Preventive Maintenance items."

The inspectors reviewed CSC Restart item V.1 as part of their inspection activities documented in NRC Inspection Report 50-461/99002, but were unable to close this restart issue due to the licensee's ineffective assessment and resolution of deficiencies associated with the deferral of PM items / tasks. Consequently, this restart item remained open pending inspector review of the root cause analysis and corrective action plan developed for CR 1-99-02-088. The licensee determined that the root cause for continuing deficiencies was inadequate change management in that personnel did not understand the new steps in the PM deferral process. Contributing factors included ineffective corrective actions and inadequate preparation and review of the CSC closure package.

Licensee planned and implemented corrective actions to resolve the deficiencies in the PM task / item deferral process included: (1) reviewing late PM tasks / items identified by the inspectors in NRC Inspection Report 50-461/99002, (2) reviewing the effectiveness of corrective actions in each of the open restart packages involving a program change, (3) briefing affected personnel on the issues associated with CR 1-99-02-088, (4) listing late PM tasks / items without a PM deferral in the operations tumover log, (5) developing a site-wide procedure for use in implementing change initiatives, (6) developing a corrective action review for effectiveness plan, and (7) completing an assessment of on-line work management.

On March 23,1999, during the development of performance indicators for late PM tasks / items, work management personnel identified that a PM task for the Division i emergency diesel generator, which had been assigned a status code of " awaiting PMT," had exceeded its late date without processing a PM deferral. The licensed initiated CR 1-99-03-306 to conduct a root cause analysis of this discrepancy and initiated a review of all PM tasks / items irrespective of the status code to determine the extent of the condition. The inspectors determined that the discrepancy was identified due to increased licensee awareness and reviews of PM activities.

The inspectors deterrnined that although problems continue to be identified, sufficient corrective actions have been implemented or planned by the licensee to ensure that PM tasks / activities are completed or that appropriate engineering justifications for deferral are evaluated prior to any PM item exceeding its assigned late date. The inspectors considered the licensee's actions appropriate to support restart.

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!- M8.4 (Closed) Case Specific Checklist Restart item V.2. " Provide Reasonable Assurance

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l that Qualified Material and Parts are Installed in Plant Systems." 1 l- The licensee submitted documentation to the NRC regarding the resolution of CSC Restart item V.2 on February 8,1999. Previous issues involving the installation of

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qualified materials and parts in plant systems were described in Licensee Event i

! Reports 50-461/97-015,98-001and 98-004. Specific issues included: (1) using l

unapproved cleaners and lubricants on plant components, (2) soldering neon indicating l~ lights with a corrosive and conductive flux, (3) using battery charger parts that had deficient soldered connections from the supplier, and (4) reissuing previously used I and/or deficient components for installation into a safety-related inverter. The licensee

! took the following actions to resolve this item:

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Development and implementation of corrective action for QA audit Q38-97-15

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In November 1997, QA personnel conducted audit Q38-97-15 and identified a decline 1 in the adequacy and effective implementation of procedures controlling procurement

< activities, the inspection of received material, and the storage of materials. As part of .

I the QA audit, five CRs were initiated involving the implementation of ANSI N18.7, i

" Administrative Controls and Quality Assurance for the Operational Phase of Nuclear

! - Power Plants," and ANSI N45.2.2, " Packaging, Shipping, Receiving, Storage, and i Handling of items for Nuclear Power Plants." Specific deficiencies documented in

these CRs included

(1) not placing the applicable code and/or standard year and

revision date on procurement documentation, (2) the potential inadequate certification i l of individuals conducting pre-off-load inspections, (3) not completing all inspections required by ANSI N45.2.2, (4) not fully evaluating inspection and test results for procured equipment, and (5) not providing sampling plans for items that had a specific shelf-life. i The inspectors reviewed the corrective actions implemented to resolve each deficiency

. and did not identify any concerns. The inspectors also reviewed the QA department's l follow-up audit, Q38-98-21, and determined that the audit was thorough and detailed.

l i Previous issues involving the improper use of consumables were discussed in NRC

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Inspection Reports 50-461/97003 and 97020. The licensee's corrective actions for

, these issues included a review of lubricant, cleaner, and flux descriptions contained in l the materials management information system and the master equipment list to ensure that the descriptions were adequate. Deficient descriptions were revised as necessary i to specify appropriate and approved uses of the materials and any associated use i limitations. Programmatic actions taken by the licensee to prevent recurrence included:

! (1) increased quality verification oversight of the use and verification that proper

. consumable materials were being used maintenance activities, (2) transferring the l responsibility for the determination and verification of proper consumables from the

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maintenance shops to maintenance planning and procurement engineering personnel, and (3) revising Procedures 1501.02, " Conduct of Maintenance," and 1029.01, " Action Request and Maintenance Work Orders," to clarify the definition and application of consumable items.

The inspectors reviewed the training provided to address the weakness in controlling l consumable materials and determined that the training was acceptable. Specific j 26 l.

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emphasis was placed on the proper application of " general plant use" and " general plant limited" materials. Based on a review of completed work, the licensee identified only one instance where an unapproved consumable was used. This incident was the result of an incomplete review by a maintenance planner; however, the material was ,

acceptable for the application. I Develop a process to ensure non-functional or degraded materials are not returned to stores for reissue.

In response to instances regarding the use of defective parts and parts being issued for reuse, materials management personnel purged maintenance shops of unused parts and returned the parts to stores. All returned parts were segregated and coded as not ready for issue. In the case of defective pars, each part was repairs and placed in stores for reuse. In addition, materials management personnel informed the inspectors that any unused part returned by an individual must be receipt inspected before i returning the part to stores for re-issue. 1 The inspectors determined that the new materials inspection process was well implemented by materials management personnel; however, the inspectors were concerned that the process was delineated in Stores Work Instruction (SWI) 012,

" Returns and Repairable," rather than through the use of a reviewed and approved procedure. The inspectors discussed this issue with the director of materials management and were informed that SWi-12 was schedu!ed to be incorporated into a procedure after startup. However, on April 6,1999, the licensee approved Advance i Chan9e Notice 5/1 to Nuclear Training and Support Procedure 9.06, " Material Issue, l Return, and lilinois Power Company Store. room Transfer," which incorporated the instructions of SWl-012 into an approved procedure. Training on the proceduralized !

process was scheduled for April 7.  !

Based on the completed corrective actions and on actions committed to be completed before startup, the inspectors determined that this item had been adequately )

addressed by the licensee. i M8.5 (Closed) Inspection Follow uo item 50-461/97006-04: This item was initiated after the inspectors identified that all site qualifications for installing freeze seals were based on training waivers rather than the completion of formal training. Revisions to the licensee's training waiver program were discussed in Section M8.2 of this report. The j inspectors considered the licensee's corrective actions to address this item adequate. j

l Ill. Enaineerina l E2 Engineering Support of Facilities and Equipment E2.1 Testina of Reserve Auxiliarv Transformer (RAT) Static Var Compensator l

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On March 23,1999, the inspectors observed operations and engineering personnel conduct testing on the RAT static var compensator (SVC). The SVC was installed as part of the licensee's degraded voltage modification effort. The inspectors determined that the testing evolution was well controlled. Potential coordination issues were

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minimized through the use of effective briefs and by providing operations personnel with just-in-time training on a portion of the test which required the simultaneous start of seven systems. No deficiencies were identified.

E8 Miscellaneous Engineering issues E8.1 (Closed) Case Goecific Checklist item IV.6. " Complete Root Cause Analysis of Recirculation Pumo Seal Failures and Develop Field Performance Measures "

On September 4,1998, the licensee submitted documentation to the NRC pertaining to I the completion of a root cause analysis for the reactor recirculation (RR) pump seal failure. The most recent RR pump seal failure was discussed in NRC Inspection Report 50-461/96010. The licensee completed the following actions to address this item:

Summary of Root Cause Analysis The licensee determined that the recurring RR pump seal degradations were caused by an inadequate seal design. Contributing factors for the degraded seal conditions were increased throttling of the RR f!ow control valves due to plant conditions, a bowed pump shaft, excessive clearances in the locating fits for the pump bearings, and occasional high particulate concentration in the seal cooling water.

l The excessive clearances were addressed through the maintenance process. To l address the other findings, the licensee recommended replacing the current RR seal design with a more robust design. Due to the long lead time required to develop and procure the new seal design, the licensee did not expect to install the new seal until the next refueling outage. The inspectors were initially concerned with the licensee's decisic,n to operate the plant with the poorly designed seal. However, the licensee developed field performance measures to ensure that the plant would be shut down if excessive RR pump seal degradation occurred during the next operating cycle.

Field Performance Measures The licensee revised Procedure 3302.01, " Reactor Recirculation," to incorporate three field performance measures. The first performance measure required operations personnel to commence an orderly plant shut down if upper seal pressure (normally 510 psig) increased to 810 psig or decreased to 270 psig. The licensee stated that the pressure limits were pr', ad by the manufacturer and that the chance of a seal failure was reduced if the set. cas taken out-of-service when these pressure limits were ;

reached. 1 The other two performance measures were based upon sealleakage. Specifically, Step 8.3.1.6 of Procedure 3302.01 requires that operators shut down the plant if a valid .

seal leakoff or seal staging flow alarm is received. The inspectors reviewed the l setpoints for the alarms and determined that the setpoints were derived from information included in the root cause analysis which stated, * ..the potential for a gross i seal failure would be low if the seals were taken out of service when the total seal outflow was below 0.5 gpm or above 2.0 gpm." In addition, the inspectors verified that

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the respective annunciator response procedures directed operations personnel to shut down the plant if a valid alarm was received. The inspectors did not identify any deficiencies based on their review of the field performance measures.

Completion of Operations Training On February 17,1999, the inspectors observed licensed reactor operator training seminar RS92927-00, " Reactor Recirculation Seal Concerns." The seminar included simulator training on the detection of RR pump seal problems, the field performance measures, and the actions to be taken if the seal leakoff or the seal staging flow alarm 1 was received. Training personnel emphasized that operations personnel must take ;

action to shut down the plant if any of the field performance measures were not )

satisfied. Operations personnel appeared to understand the new expectations )

regarding RR pump seat performance. No deficiencies were identified during the training.

The inspectors considered the licensee's corrective actions to resolve the RR pump seal failures and to develop and implement appropriate field performance measures sufficient to support plant restart.

E8.2 (Closed) Licensee Event Report (LER) 50-461/99-001: Improper assembly of motor causes degradation of bearings in two divisions of shutdown service water system.

This issue was discussed in NRC Inspection Report 50-461/99002 and two violations were identified. In response to this issue, the licensee committed to: (1) revise procedures and vendor manuals associated with motors susceptible to shaft currents to ensure the insulating requirements are identified, (2) develop a training seminar that described why and how components are insulated to protect against shaft currents, and (3) brief maintenance planners prior to the completion of the procedure changes and the training seminar. No new issues were identified in the LER.

V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 7,1999. The licensee acknowledged the findings l presented. The inspectors asked the licensee whether any matenals examined during the inspection should be considered proprietary. No proprietary information was identified.

X3 Management Meeting Summary On March 18,1999, a meeting was held on-site to discuss licensee restart activities and improvement initiatives as well as NRC activities associated with implementation of Manual Chapter 0350, " Staff Guidelines for Restart Approval." Specific topics included operations staff performance, work management issues, safety system engineering inspection results, and the status of licensee actions to address the remaining restart issues listed in the Manual Chapter 0350 Case Specific Checklist. j

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On March 25,1999, a meeting was held on-site to discuss licensee restart activities and improvement initiatives as well as NRC activities associated with implementation of Manual Chapter 0350. Specific topics included operations department readiness for restart, corrective action program effectiveness, and the status of licensee actions to address the remaining restart issues listed in the Manual Chapter 0350 Case Specific Checklist.

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! PARTIAL LIST OF PERSONS CONTACTED I icong,qe J. McElwain - Chief Nuclear Officer G. Hunger, Plant Manager - Clinton Power Station D. Warfel, Manager- Nuclear Station Engineering Department R. Phares, Manager - Nuclear Safety and Performance improvement G. Baker, Manager - Quality Assurance J. Goldman, Manager - Work Management V. Cwietniewicz, Manager - Maintenance H. Anagnostopoulos, Director - Plant Radiation and Chemistry J. Gruber, Director - Corrective Action W. Maguire, Director - Operations J. Sipek, Director - Licensing D. Smith, Director - Security and Emergency Planning INSPECTION PROCEDURES USED IP 37551: Engineering Observations IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Follow . - Engineering

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l l ITEMS OPENED, CLOSED, AND DISCUSSED l '929E9d 50-461/99006-01 NCV Failure to provide oversight to maintain professional atmosphere in the main control room.

50-461/99006-02 NCV Failure to perform required post maintenance testing on containment isolation valve following maintenance.

50-461/99006-03 NCV Failure to perform safety evaluation for revision to Procedure 1029.03.

50-461/99006-04 NCV Failure to control overtime for FIN team members.

Closed 50-461/99006-01 NCV Failure to provide oversight to maintain professional atmosphere in the main control room.

50-461/99006-02 NCV Failure to perform required post maintenance testing on containment isolation valve following maintenance.

50-461/99006-03 NCV Failure to perform safety evaluation for revision to Procedure 1029.03.

50-461/99006-04 NCV Failure to control overtime for FIN team members.

50-461/97006-04 IFl Extensive use of training waivers.

50-461/99-001 LER Improper assembly of motor causes degradation of bearings in two divisions of shutdown service water system.

CSC ltem 11.3 Review and revise abnormal operati,ons sections of operations procedures.

CSC ltem II.4 Establish and implement an effective risk assessment program.

CSC ltem IV.2 Provide reasonable assurance that deficiencies affecting safety-related SSCs have been identified and corrected.

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CSC ltem IV.6 Complete root cause analysis of recirculation pump seal failures and develop field performance measures.

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CSC ltem V,1 Develop process to review deferrals of preventive maintenance items.

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P CSC ltem V.2 Provide reasonable assurance that qualified material and parts are installed in plant systems.

Discussed CSC ltem 11.1 Establish and implement continuing operator training emphasizing Technical Specification adherence / knowledge and recognition of degraded conditions.

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! LIST OF ACRONYMS AP Auxiliary Power CCF Comment Control Form CR Condition Report I CRC Curriculum Review Committee CRS Control Room Supervisor i CSC Case Specific Checklist I DC Direct Current DRP Division of Reactor Projects FIN Fix-it-now IN Information Notice LCO Limiting Condition for Operation LER Licensee Event Report MCR Main Control Room ODCM Offsite Dose Calculation Manual ORM Operations Requirements Manual PDR Procedure Deviation for Revision PFE Plan for Excellence i

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PM Preventative Maintenance PMT Post Maintenance Testing PRA Probabilistic Risk Assessment OA Quality Assurance RAT Reserve Auxiliary Transformer ;

RCIC Reactor Core Isolation Cooling

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RG Regulatory Guide RHR Residual Heat Removal RO Reactor Operator RR Reactor Recirculation System SA Service Air System SDFV System Design and Functional Validation SET Special Evaluation Team SSC Structure, System, or Component SSEI Safety System Engineering inspection SVC Static Var Compensator SX Shutdown Service Water SY Switchyard TM Temporary Modification TPD Temporary Procedure Deviation TS Technical Specification USAR Updated Safety Analysis Report VD Diesel Ventilation WS Service Water 34