IR 05000461/1998008

Insp Rept 50-461/98-08 on 980414-0528.Enforcement Discretion Has Been Authorized for Listed Violations.Major Areas Inspected:Aspects of Licensee Operations,Engineering,Maint & Plant Support

ML20236F057
Person / Time
Site:	Clinton
Issue date:	06/25/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20236F056	List: IR 05000461/1998008 ML20236F052
References
50-461-98-08, 50-461-98-8, NUDOCS 9807020007
Download: ML20236F057 (23)

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U.S. NUCLEAR REGULATORY COMMISSION l

REGION 111 Docket No.: 50-461 L License No.: NPF-62

Report No: 50-461/98008(DRP)

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Licensee: Illinois Power Company Facility: Clinton Power Station Location: Route 54 West Clinton, IL 61727 Dates: April 14 through May 28,1998 l

Inspectors: T. W. Pruett, Senior Resident inspector i K. K. Stoedter, Resident inspector C. E. Brown, Resident inspector D. E. Zemel, Illinois Department of Nuclear Safety Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4 I

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9907020007 990625 :

PDR ADOCK 05000461

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EXECUTIVE SUMMARY l

Clinton Power Station NRC Inspection Report 50-461/98008(DRP)

This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspectio Operations 1

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The inspectors identified severalitems that had not been considered during the licensee's material condition review to declare Electrical Division il operable. The items were resolved, and the inspectors determined that Division ll was operable for Mode 4 (Section 01.1).

. The inspectors identified one example of a poor questioning attitude which involved the ability of operations personnel to recognize changing plant risk conditions during periods of degraded grid voltage (Section 01.2).

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The inspectors concluded that operation's logs included sufficient detail to describe plant activities, compensatory measures for out-of-service annunciators were appropriate, and coordination and contingency plans referenced approved procedures (Section O3.1).

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The inspectors identified a violation for the failure to verify each secondary containment manual isolation device closed every 31 days as required by Technical Specifications between discovery on June 18,1996, and initial performance of the implementing surveillance prncedure on December 1,1996 (Section 08.1).

The inspectors identified a violation for not irnplementing corrective actions to preclude the failure to perform verifications on all primary containment manual isolation devices as required by Technical Specification's following a similar discovery affecting secondary containment manualisolation devices in June 1996 (Section 08.8).

Maintenance

• The inspectors concluded that procedures were not adequately adhered to when maintenance workers failed to return an MWR to planning personnel for revision following the change in scope of the Division l EDG Var meter calibration on two occasions (Section M1.2).

• The inspectors concluded that an adequate procedure was not established and implemented for the installation of a clamp-on device on a safety-related motor power feed wire to monitor various parameters (Section M1.3).

• The inspectors identified a violation for failing to implement corrective actions for licensee identified discrepancies in the air operated valve program. Maintenance department self-assessments were weak in that four of five completed assessments did not determine if program elements were effectively implemented (Section M7.1). i

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The inspectors determined that quality assurance inappropriately provided a positive review of maintenance department self-assessments in that: only five of eight scheduled audits were completed, condition reports were not generated, action items were assigned without due dates for completion, due dates for action items were allowed to be extended without approval by the respective manager, Task Performance Check Lists were not l tracked or trended to provide performance indicators, and results from Task Performance Check Lists were not consistent with results from other performance monitoring systems (Section M7.1).

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i Report Details l

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Summary of Plant Status The plant remained shut down during the inspection period. Major activities completed included the restoration of the Division i EDG and emergency core cooling systems to an operable Mode 4 status. The restoration of this equipment was significant in that many of the components had been inoperable but available since August 199 l I

1. Operations 01 Conduct of Operations  !

0 Evaluation of Plant Mode Restraints f71707) Inspection Scope  ;

l The inspectors reviewed deficiencies associated with the Division II EDG and RHR Systems to determine if the licensee appropriately declared Division 11 components operable for Mode l l Observations and Findinas The inspectors reviewed the mode restraint list, MWRs, condition reports (CRs) and engineering evaluations for the Division II EDG and RHR systems to ensure the licensee appropriately retumed Division ll systems to an operable. for Mode 4 status. The  ;

inspectors determined that the licensee's review of material condition issues, tracked in over 30 different systems, was generally effective in ensuring that operations personnel appropriately returned components to an operable for Mode 4 status. The inspectors noted that the muhiple tracking systems were cumbersome and made identification of Mode restraints difficult. As a result, the inspectors identified the following that were not considered prior to declaring the equipment operable and required resolution;

• CR 97-09-252 documented a discrepancy involving 1he setpoint for the RHR minimum flow valve. The inspectors noted that the di';crepancy had not been added to the mode restraint list. After further discusrion with operations and engineering personnel, the licensee added resoluilon of the item to the Medes 1 and 2 restraint lis . CR 96-10-381 documented a discrepancy with testing the ability to transfer EDG loads to both the 345 kV and 138 kV off-site power sources. The inspectors noted that the discrepancy had not been added to the mode restraint list and the licensee's initial review did not recognize the impact on Mode 4 operability. Upon further review, the licensee was able to provide sufficient documentation to show that adequate overlap testing existed to reasonably demonstrate the capability to transfer EDG loads to both off-site power source .

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Several CRs were listed in the "other" section of the mode restraint list. Examples  !

l of affected components included Westinghouse circuit breakers, control room j neon indicating lights, and EDG ventilation. The licensee stated that the "other" section included items operations personnel wanted resolution on before plant l restart and did not necessarily include any technicalissues. However, the l inspectors noted that the items were not viewed as restart issues in the licensee's Plan For Excellence. The licensee stated that a review of the "others" section of the mode restraint list would be performed to ensure a central tracking system  !

existed for plant restart issue l l

An additional question was raised concerning electrical hot shorts. In a memorandum to licensing file dated October 24,1997, engineering personnel notified operations personnel that electrical hot shorts were not an issue for Mode 4 because effected components were assumed to be repairable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Between October 24,1997 and May 5,1998, operations personnel assumed Division 11 components were unaffected by the hot short issue based on the licensing memorandum to fil Between April 23 - 27,1998, engineering personnel informed the inspectors that 10 CFR Part 50, Appendix R, Section G.b, allowed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for repair of components and that the components affected by a fire causing a hot short condition could be repaired within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The inspectors questioned engineering and operations personnel to determine which components were anticipated to be damaged by a hot short, how the component would be damaged, and whether or not the damage could be repaired within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The licensee was unable to provide any documentation or evaluation to resolve the inspectors' concerns. The inspectors considered the initial operability declaration based on the ability to perform repairs within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, without an engineering evaluation to support possible failure modes, an example of poor questioning attitude by operations and engineering personne On May 5,1998, the licensee completed engineering evaluation 1-97-06-214-0 which specified that hot shorts were not an operability concern unless the plant was in Modes 1 or 2 and that declaring Division 11 operable for Mode 4 was acceptable per the licensing basis. The inspectors reviewed engineering Evaluation 1-97-06-214-0 and support references and agreed with the licensee's position that hot shorts were not an operability issue for Mode 4 Conclusions

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Although the inspectors identified severalitems that had not been considered during the i licensee's material condition review to declare electrical Division il operable, the items were resolved and the inspectors determined that Division 11 was operable for Mode .2 Plant Risk Assessment (71707) Inspection Scope The inspectors reviewed the licensee's assessment of plant risk during periods when both off-site power sources were below the minimum voltage for operabilit l

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l Observations and Findinos i l

On May 15,1998, the 345 kV reserve auxiliary transformer power supply and the 138 kV emergency reserve auxiliary transformer power supply grid connections were below the i voltage required by Procedure 9082.02, " Electrical Distribution Verification Mode 4 and 5, l During Movement of irradiated Fuel Assemblies in the Primary or Secondary '

Containment," and it's associated predictor model software. Operations personnel i declared both power supplies inoperable but available and maintained the associated risk l level" GREEN", which is the least risk significant conditio Procedure 1151.09., " Methodology for Outage / Safety Reviews and Maintenance of Acceptable Shutdown Risk," Attachment 1, specified that a shutdown risk level of " RED,"

which is the most risk significant condition, should be assigned to ac power if there is less than 1 on-site and/or less than one off-site source available. The term "Available"is defined in Procedure 1151.09, Section 2.2.1, as a system, structure, or component that is capable of performing its intended function (s).

The inspectors discussed the plant risk assessment for degraded voltage conditions with !

the operations manager and the work management manager on May 18 and May 2 l Both managers concluded that a " RED" risk level should have been applied and initiated l

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CR 198-05-240. The managers stated that if the offsite power source was inoperable it should also be considered unavailable since the system may not be capable of performing its intended function. The inspectors reviewed the plant conditions during the degraded voltage period and noted that no additional compensatory actions were require Conclusions The inspectors identified an example of a poor questioning attitude which involved the failure of operations personnel to recognize changing plant risk conditions during periods of degraded grid voltag O3 Operations Procedures and Documentation O Review of Operations Loos Inspection Scope _]71707)

The inspectors performed reviews of operating logs and contingency plan Observations and Findinos The inspectors performed a review of the station log, out-of-service annunciator log, and contingency plans. In general, the operations station log provided sufficierst detail to describe plant activities. The annunciator log documented out-of-service annunciators and provided appropriate compensatory measures.

, Contingency plans generally referenced actions to be taken in accordance with approved procedures. However, Contingency Plan 98-024, " Division i Inverter Outage," referenced l actions which were to be completed in accordance with Temporary Procedure Deviation

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(TPD) 98-0291 for Procedure 3312.03, "RHR - Shutdown Cooling (SDC) & Fuel Pool l Cooling and Assist (FPC&A)." The inspectors noted that a safety evaluation for the TPD had not been completed when Contingency Plan 98-024 was issued. Although the TPD had received a safety evaluation within the allotted 14 day period following initiation of the TPD as required by Procedure 1005.07, " Temporary Changes to Station Procedures and Documents," operations management stated that they had not considered the need for performing an expedited safety evaluation for TPDs referenced in a contingency plan. In response to the inspectors concerns, the licensee established guidance to ensure that TPDs used for a contingency plan had an approved safety evaluation before implementation, Conclusions The inspectors concluded that operation's logs included sufficient detail to describe plant activities, compensatory measures for out-of-service annunciators were appropriate, and coordination and contingency plans referenced approved procedure Miscellaneous Operations issues (92901)

0 (Closed) Licensee Event Report (LER) 50-461/96009: Failure to perform Technical Specification (TS) surveillance requirement involving verification of secondary l containment isolation valves. Procedure 9065.01, " Secondary Containment Access Integrity," was used to fulfill TS surveillance requirement 3.6.4.2.1, which required that secondary containment isolation devices required to be closed be verified as closed every 31 days. However, Procedure 9065.01 only specified that a small percentage of the devices required to be closed be verified as closed. On June 18,1996, while in Mode 1, operations personnel questioned whether or not Procedure 9065.01 fulfilled the intent of TS surveillance requirement 3.6.4.2.1. CR 196-06-047 was written to document and resolve the questio On June 19,1996, operations personnel performed TS surveillance 3.6.4.1.4 and 3.6.4.1.5, which verified that the standby gas treatment system (SGTS) could draw down and maintain a vacuum of greater than or equal to 0.25 inches of vacuum in the secondary containment in accordance with Procedure 9065.02, " Secondary Containment integrity." The licensee believed that the SGTS draw down test was equivalent to the 31 day verification that secondary containment manual isolation devices were in the closed position and considered TS surveillance 3.6.4.2.1 to be satisfie Licensee Letter Y-217659," Acceptability of the Continued Use of CPS No. 9065.0 During Resolution of CR 1-96-06-047," dated July 17,1996, documenting the licensee's assumption that the SGTS draw-down test adequately, demonstrated the leak tightness of secondary containment. Specifically, the licensee indicated that Procedure 9065.02 acceptance criteria could not be met if all secondary containment manual valves, dampers, or blind flanges were r,ot verified closed as required by TS surveillance requirement 3.6.4.2.1. The inspectors reviewed Procedure 9065.02 and determined that the acceptance criteria verified the ability to draw down secondary containment but did not specifically verify that ecch secondary containment isolation manual valve, damper, _

and blind flange were closed. On August 8,1996, licensing personnel determined that Procedure 9065.01 did not meet the requirements of TS surveillance requirement 3.6.4. ___ _

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Licensee Letter Y-217703, " Required Scope of TS Surveillance Requirement 3.6.4.21 in Support of Resolution of CR 1-96-06-047," dated August 23,1996, indicated that secondary containment penetrations required to be closed during accident conditions are those with a potential to communicate directly with secondary containment atmosphere and contribute to excessive secondary containment in-leakage. These openings must be controlled to ensure the capability of the SGTS to draw down the secondary containmen For pressurized systems, Licensee Letter Y-217703 indicated that routine tours of plant areas would ensure the isolation integrity of pressurized systems in that mispositioned isolation devices would be readily identified. For depressurized systems, Licensee Letter Y-217703 indicated that leakage from mispositioned isolation devices would not be readily identified and that the SGTS draw down test of secondary containment would detect excessive leakage. Therefore, the licensee decided to continue performing TS surveillance requirements 3.6.4.1.4 and 3.6.4.1.5 (verification that the SGTS can draw dawn and maintain a vacuum in the secondary containment) to meet the requirements of TS surveillance requirement 3.6.4.2.1 (verification that each secondary containment isolation manual valve, damper, and blind flange, that is required to be closed during accident conditions, is closed).

The inspectors noted that the TS Bases described separate purposes for the TS surveillance requirements. Technical Specification Bases 3.6.4.1.4 and 3.6.4. specified that the tests were used to ensure secondary containment boundary integrit Technical Specification Bases 3.6.4.2.1 specified that the test helped to ensure that post accident leakage of radioactive fluids or gases outside of the secondary containment boundary is within design limits. The inspectors noted that while the draw down test verifies the structuralintegrity of secondary containment, it does not necessarily determine the extent of all system leakage outside of secondary containmen After considering the inspectors' questions, on November 8,1996, the licensee revised Procedure 9065.01 to include a list of secondary containment manualisolation devices requiring verification every 31 days. The revised Procedure 9065.01 was initially performed on December 1,1996. The inspectors determined that the corrective actiens to revise and perform Procedure 9065.01 were appropriate for the secondary containment isolation device requiremen Technical Specification surveillance requirement 3.0.3 states that if a surveillance is not performed within the delay period, the Limiting Condition for Operation must be declared not met, and the applicable Condition (s) must be entered. Technical Specification 3.6. required that each sccondary containment isolation damper be operable during Modes 1, 2, and 3, during the movement of irradiated fuel assemblies in the primary or secondary containment, during core alterations, and during operations with a potential for draining the reactor vessel (OPDRV). Condition C specified that with the Required Action and Completion Time of Condition A or B not met in Mode 1,2, or 3, then the plant must be piaced in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Condition D requires the licensee to immediately suspend movement of irradiated fuel assemblies, suspend CORE ALTERATIONS, and initiate actions to suspend OPDRVs. These conditions were never entered as required by TS surveillance requirement 3.0.3. The inspectors determined that the failure to implement the limiting conditions for operation associated with TS 3.6.4.2 Detween discovery on June 18,1996, and initial performance of the implementing surveillance procedure on December 1,1996, a violation of TS surveillance

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requirement 3.0.3. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations Identified During Extended Shutdowns or Work Stoppages,"

of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98008-01).

08.2 (Closed) Licensee Event Report 50-461/98-005: Failure to verify all primary containment manual isolation devices closed every 31 days. During a review of TS surveillance requirement 3.6.1.3.2, which requires each primary containment isolation manual valve and blind flange that is located inside the primary containment, the drywell, or the stsam tunnel that is required to be closed under accident conditions to be closed every 31 days, the licensee discovered that three valves had not been verified closed. During a review of TS surveillance requirement 3.6.1.3.3, which requires that each primary containment isolation manual valve and blind flange that is located outside the primary containment, the drywell, or the steam tunnel and is required to be closed under accident conditions be verified to be closed before entering Mode 2 or 3 frrsm Mode 4, the licensee discovered that four devices had not been verified close The licensee determined that five of the seven valves and devices had been inadvertently excluded from the implementing surveillance procedure. Two of the devices were not added to the implementing procedure following a plant nwdification in 199 The inspectors noted that the licensee did not include as a similar event the failure to verify secondary containment manualisolation devices described in LER 96-009 in the submittal for LER 98-005. In addition, the inspectors noted that the licensee's corrective actions for LER 96-009 did not include a review to determine whether or not primary containment manualisolation devices were being verified closed.10 CFR Part 50, Appendix B, Criterion XVI, requires that in the case of significant conditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective actions taken to preclude repetition. The failure to implement corrective actions to preclude the failure to perform verifications that all primary containment manual isolation valves were closed, following a similar discovery effecting secondary containment manualisolation devices, is considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98008-02).

08.3 (Closed) Notice of Violation 50-461/96009-01: Inadequate guidance in nuclear system performance system checklist to prevent inadvertent system isolation. In response to this violation, the licensee revised the respective procedures to provide guidance and prevent future inadvertent system isolations. The inspectors reviewed the procedure changes and identified that the steps for the Division I checklist were not written in the same order as the checklists for the remaining three divisions. The inspectors discussed this observation with a procedure writer and were informed that the Division I checklist would be revised to ensure the steps were in the proper orde _ _ _ _ _ _ _

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08.4 (Closed) Inspection Followup item 50-461/96011-01: Potentially nonconservative j reactivity manipulations. This inspection follow-up item (IFI)is a duplicate of IFl 50-461/97012-01 therefore, a review of reactivity manipulations by operations personnel will be performed as part of the closeout activities for IFl 50-461/97012-0 .5 (Closed) Unresolved item 50-461/96015-06: Adequacy of licensee's safety function determination program. The inspectors reviewed the procedures goveming the safety l function determination program and identified that the procedures appropriately l implemented TS requirements and provided adequate guidance for determining if a loss of safety function had occurred for support and supported systems. No additional concerns were identifie .6 (Closed) Notice of Violation 50-461/96412-07: This item was initially documented in NRC inspection Report 50-461/96011. This violation involved the failure of the line assistant

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shift supervisor to perform and adequate turnover to a relief operator. Specific corrective actions involved a revision to operating procedures regarding the conduct of short-term reliefs. Expectations regarding turnovers were communicated during operations training sessions. Frequent observations by NRC inspectors following the occurrence of the  !

violation have not noted any further examples of inadequate turnovers between relief l operator I O8.7 (Closed) Unresolved item 50-461/97006-07: Failure to account for instrument inaccuracies results in potentially inadequate surveillant ocedures. This unresolved item is a duplicate of Licensee Event Report (LER) 50-461/v7-009, therefore, the licensee's corrective actions for this event will be reviewed as part of the LER closeout activitie l 08.8 (Closed) Unresolved item 50-461/98003-05: Review of operations department's ability to meet manning requirements specified in emergency plan during a control room fire requiring evacuation. In discussions with the licensee, the inspectors learned that the safe shutdown analysis stated that actions to place the plant in a shutdown condition could be performed by locating one operator at the remote shutdown panel and one operator in the field. The inspectors reviewed the activities delineated in Procedure 4003.01, " Remote Shutdown," and concurred with the statement in the safe shutdown analysis. Based upon this new information, the inspectors determined that the current number of people on shift should be adequate to ensure that emergency plan I functions can be performe II. Maintenance M1 Conduct of Maintenance i M1.1 General Comments (61726 and 62707)

h Portions of the following maintenance and surveillance activities were observed or i reviewed by the inspectors: I Procedure 9866.05 Control Room Ventilation Duct Heater Performance Test Procedure 9866.02 Standby Gas Treatment / Control Room Ventilation Charcoal Absorber Leak Test i I

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MWR D85434 ' Inspection of Coupling Bolts on Control Room Ventilation Chilled Water Pump OVC08PA to Verify Head Markings MWR D81987 Replacement of Hydramotor on Control Room Ventilation Return Damper OVC04YB MWR D79347 Replacement of Meter Face and Calibration of Division ll EDG Var Meter 1JI-DG094 M L2 CMibration of Division i EDG Load Reactive Meter Inspection Scope (62707)

The inspectors observed electrical maintenance personnel perform a ca:ibration of the Division i EDG load reactive meter,1JI-DG09 Observations and Findinas On May 7,1998, the inspectors observed work in progress in the Division i EDG local control panel which involved calibrating the load reactive meter. During review of MWR 79347, the inspectors noted that electrical maintenance personnel had changed the scope and intent of the package on two occasions without approval. Specifically, electrical maintenance originally decided not to perform a meter calibration following replacement of the meter face and then subsequently changed the method of performing the calibratio MWR 79347 was originally assigned to the Fix-it-Now (FIN) team. The scope of the task was to install a new meter cover and calibrate Varmeter 1JI-DG094. On May 6,1998, the FIN team decided that replacing of the meter face did not affect the indication and chose not to perform the required calibration. The inspectors noted that a revision to the MWR was not performed to delete the requirement to perform a calibration. FIN team personnel stated that it was acceptable for the craft to use their discretion to delete items within an approved MWR without performing a revision to the package or receiving supervisory approvalin advance of changing the MW Upon completion of the meter face replacement, a maintenance group supervisor signed for closing the package, however, he did not ensure that the steps described in MWR 79347 were completed and that each step in the MWR was documented as being completed. The supervisory review of MWR 79347 was contrary to the February 19,1998, letter from the director of maintenance which specified that all MWR packages closed by maintenance personnel be closed utilizing CPS 1029.01C002, "MWR Closeout Review Checklist." in response to the inspectors observations, the director of maintenance stated that not all personnel had received the letter requiring the use of the checklist for document closure and that he had reenforced his expectations regarding the need to ensure maintenance packages received a thorough review before closure in a letter to all maintenance personnel dated May 15,199 On May 7,1998, following closure of MWR 79347, electrical maintenance personnel determined that a meter calibration was required since the indicator could have been j improperly set during the meter face replacement. Electrical maintenance personnel j performed the calibration using the previously closed MWR 79347 package. Electrical '

maintenance personnel performing the task decided to perform the calibration from the

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EDG local control panel in lieu of the switchgear as described in MWR 79347. Electrical i maintenance personnel stated that it was acceptable for the craft to use their discretion to i change the method of performing calibrations described in an MWR without performing a revision to the package or receiving supervisory approvalin advance of changing the l MWR. In response to the inspectors' observations, the director of maintenance issued a

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letter to all maintenance personnel dated May 15,1998, reinforce management expectations with regard to the scope of work in the MWR being aligned to the problem description, work being performed as described in the job steps, that broad work scopes and discretion are minimized, and that job steps are signed as completed.

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Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, recommends procedures for performing maintenance that can affect the performance of l safety-related equipment. Procedure 1501.02," Conduct of Maintenance,"

Section 8.1.2.2, specified that if a revision to the MWR is necessary, return the package to planning personnel. Procedure 1029.01," Preparation and Routing of Maintenance Work Documents," Section 5," Revisions," specified that if the scope of work has changed, include a new scope of work based on the changes made to the MWR. The

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failure of FIN team and electrical maintenance personnel to retum MWR 79347 to planning personnel for revision on the two occasions mentioned above were two examples of a violation of TS 5.4.1.a. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98008-03). Conclusions The inspectors concluded that procedures were not adequately adhered to when maintenance workers failed to return an MWR to planning personnel for revision following the change in scope of the Division i EDG Var meter calibration on two occasion M1.3 Obtainino Motor Operatino Data (62707)

a. Inspection Scope The inspectors observed maintenance and engineering personnel during the acquisition of motor data utilizing a clamp-on device at 480 volt unit sub station, Division 11, OAP24 ' Observations and Findinas On May 1,1998, the inspectors observed engineering and maintenance personnel performing a test in 480 volt unit sub station, Division 11, OAP24E - a safety-related motor control center - with no approved instructions, procedures, or drawings. The work i involved installing a clamp-on device on a motor power feed wire and recording various L measured parameters with a hand held computer. When questioned, electrical maintenance personnel stated that they were assigned to support the system engineer in

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obtaining the data. The system engineer stated that a procedure was being written for doing this type of work but that it had not been approved. The system engineer also stated that operations personnel in the main control room had been briefed and had approved taking the test data. The operations shift manager stated that the operator who had released the work thought the activity had been defined in an open MWR for post maintenance testin Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 197 Regulatory Guide 1.33, recommends procedures for performing maintenance that can affect the performance of safety-related equipment. The failure to establish a procedure for performing clamp on measurements is considered a violation of TS 5.4.1.a. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98008-04). Conclusions The inspectors concluded that an adequate procedure was not established and implemented for the installation of a clamp-on device on a safety-related motor power feed wire to monitor various parameter M7 Quality Assurance in Maintenance Activities M7.1 Maintenance Department Self-assessments Inspection Scope (62707)

The inspectors performed a review of maintenance department self-assessments and Task Performance Checklists (TPCLs). Observations and Findinas Formal Self-Assessments The October 1997 maintenance department self assessment schedule included eight formal self-assessments, three of which were not performed. The inspectors reviewed the five completed assessments and noted that four of the five self-assessments were not appropriately critical of the program areas assesse The maintenance department self assessment of the air operated valve program completed November 7,1997, determined that there was no program manager, little or no engineering involvement, no established method of scheduling valves, no trend analysis of test data, and that only Fisher Modulating Control Valves and Actuators were

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tested. The inspectors noted that a CR had not been initiated to address these finding Maintenance personnel stated that even though a CR had not been initiated, corrective actions for the air operated valve program discrepancies were being tracked using the plant staff action tracking databas The inspectors reviewed the plant staff action tracking database and determined that due dates had not been assigned for actions involving the air operated valve progra Additionally, action items in the database could be extended by a supervisor without approval from their respective manager or director. The inspectors also noted that as of May 1,1998, actions to address the deficiencies in the air operated valve program had not been initiated.10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that conditions adverse to quality are promptly identified and corrected. The failure to implement corrective actions following the determination that the air operated valve program was inadequate is a violation of 10 CFR Part 50, Appendix B, Criterion XV However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2,

" Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy),

NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/98008-05).

Informal Self-Assessments The inspectors reviewed the use of TPCLs which are used as an informal method of self-assessment and were developed to provide a mechanism to document the reinforcement of management expectations through increased supervisory oversigh Based on field observations, supervisory personnel documented the performance of maintenance personnelin areas involving safety, procedure use and adherence, task readiness, job performance, human performance, and supervisory oversigh Approximately 1,000 TPCLs were initiated between January 1 and March 31,1998, in the mechanical maintenance, electrical maintenance, and control and instrumentation area The inspectors determined that the TPCLs were not effectively implemented in that only the safety area was tracked and trended. The remaining areas were reviewed by the respective supervisor as the TPCL was generated without integration of issues from previously generated TPCLs. No negative human performance issues (professionalism, self checking, and independent verification) were identified on TPCLs, even though approximately half of the CRs affecting the maintenance department during the same period identified human performance related issues. No safety issues (industrial safety, conservative decision making, protective equipment, and radiological safety) were identified in the electrical or control and instrumentation disciplines. Lastly, the majority of negative comments focused on areas outside the responsibility of the maintenance discipline performing the task (e g.; quality of the maintenance package and inadequate walkdown of task).

Quality Assurance (QA) Review of Maintenance Self-Assessments The inspectors reviewed QA audit Report Q38-97-11 regarding self-assessments dated, November 17,1997, and QA audit Report Q38-98-04 regarding plant staff maintenance, dated April 7,1998. Both audit reports determined that the maintenance department was meeting the requirements of Procedure 1005,16 "Self Assessment," which included the

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l schedule, reporting the results, method of tracking actions, and reporting results to the Vice-President. The inspectors determined that QA inappropriately provided a positive review in that only five of eight scheduled audits were completed, CRs were not generated for deficiencies, action items were assigned without due dates for completion, due dates for action items were allowed to be extended without approval by the respective manager, TPCLs were not tracked or trended to provide performance indicators, and results from TPCLs were not consistent with results from other performance monitoring system The QA manager acknowledged that the audits of departmental self assessments were not appropriately critical and stated that the audits failed to identify that the self-assessments had focused on the quality of the program with respect to industry practices in lieu of implementation of program elements at the station. Improvements in the licensee's ability to perform self-assessments will continue to be reviewed as part of the NRC's 0350 panel oversight of the facilit Conclusions The inspections concluded that appropriate corrective actions were not implemented for licensee identified discrepancies in the air operated valve program. Maintenance department self-assessments were weak in that the assessments did not determine if program elements were effectively implemented. The inspectors also concluded that QA audits inappropriately provided a positive review of maintenance department self-assessments when they were actually wea M8 Miscellaneous Maintenance issues (92902)

M8.1 Closed Notice of Violation 50-461/97006-03a throuah 03a: Failure to document MWR job steps, perform steps as directed, and evaluate risk basis deviations. The inspectors reviewed the results of licensee assessments involving documentation of items in MWRs and the performance of engineering evaluations for risk basis deviations. QA Assessment 98-2-5676, performed between January 28 - February 18,1998, identified that the failure to document completion of activities in MWRs was a generic maintenance department weakness. On February 19, the director of maintenance issued letter VJC-002-98 requiring maintenance personnel to use the MWR and preventive maintenance closeout review checklists. Additionally, all packages which had not been j sent to records for storage were held in the maintenance shops until the appropriate checklist was complete M8.2 (Closed) Unresolved item 50-461/98006-01: Adequacy of coatings procedure was questioned due to lack of specified limits for relative humidity during coatings application. 4 Since the previous inspection period, the licensee obtained further clarification from the l coatings manufacturer (by letter dated April 30,1998, licensee file number C79-98(04-30)-6) regarding coating application limits. Based on review of the manufacturer's letter, the inspectors concluded that if the surface temperature was 5'F above dewpoint temperature, coating application was acceptable even if the relative humidity exceeded 90 percent. Procedure 8901.08, " Field Coatings," had appropriately incorporated the surface temperature requirement and the lack of relative humidity requirements in the procedure was acceptabl l

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111. Enaineerina E8 Miscellaneous Engineering issues (92903)

E8.1 (Closed) Inspection Followup Item 50-461/96010-03: Review of vendor recommendations regarding the recirculation pump seals. Following the September 1996 I reactor recirculation pump seat failure, the licensee formed a task force to review pump

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performance and to identify potential contributors to the long-standing reactor recirculation pump seal performance problems. The inspectors considered the licensee's actions appropriate for this issue. In addition, this item is being tracked in the NRC MC 0350 proces E8.2 (Closed) Licensee Event Report 50-461/96-017: Misinterpretation of time delay relay setpoint data results in Division ill EDG being unable to energize its emergency bus within the TS time limit, Corrective actions for this issue were reviewed during the closecut of violations 50-461/96412-20 and -21 (see Sections E8.3 and E8.4). The inspectors considered the licensee's actions appropriate for this issu E8.3 (Closed) Notice of Violation 50-461/96412-20: Failure to properly calibrate Division 111 EDG relay resulted in EDG being inoperable for approximately a year. This item was  !

previously discussed in NRC Inspection Report 50-461/96014. The licensee determined j that this violation occurred due to a lack of questioning attitude and weaknesses in the i failure coding and trending program. In response to this issue, maintenance personnel successfully recalibrates and retested the relay. In addition, the licensee began requiring that all safety-related instruments found out-of-tolerance during calibration be i

documented in a CR to ensure that corrective actions would be pursued in a timely '

manner and to a!!ow trending. The inspectors considered the licensee's actions appropriate for this issu E8.4 (Closed) Notice of Violation 50-461/96412-21: Failure to property 0 v. late design basis information regarding a Division 111 EDG relay into the appropriate procedures. This item was previcusly discussed in NRC inspection Report 50-461/96014. The licensee determined that this violation occurred due to personnel error and poor drawing qualit In response to this violation, the licensee revised the relay calibration sheet to reflect the correct time delay setting and improved the quality of the corresponding drawin Engineering personnel reviewed several preventive maintenance calibration activities to ensure that the calibration settings were correct. Lastly, an independent assessment of the nuclear station engineering department was performed which identified several performance weaknesses. The licensee planned to address these weaknesses as part of l the Plan For Excellence. The inspectors consi6ered the licensee's actions appropriate for this issu ,

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E8.5 (Closed) Notices of Violation 50-461/96412-22. -23. -24. -25. and -26: Failure to perform 10 CFR Part 50.59 safety evaluations for engineering action plans. These violations were originally documented in NRC Inspection Report 50-461/96011. Corrective actions involved the development of Procedure 1070.01, " Coordination Plans," which required that procedures be referenced or a procedure be developed for equipment manipulation in lieu of specifying equipment operation in an unreviewed document. The inspectors reviewed multiple coordination and contingency plans and noted that the appropriate approved procedure was referenced for equipment manipulation The licensee also initiated corrective actions to improve the quality of safety evaluation However, in April 1998, QA personnel completed a review of the safety evaluation process and determined that while the program elements were satisfactory, the implementation of the safety evaluation program remained inadequate. The inspectors noted that NRC Confirmatory Action Letter (CAL), Rlll-97-001, addressed the need to provide training on 10 CFR Part 50.59. The NRC's review of the CAL response concluded that the training was adequate, however, an assessment to validate the quality of 10 CFR Part 50.59 safety evaluations was not performed. A review to assess corrective actions regarding the pocr quality of 10 CFR Part 50.59 safety evaluations will be performed as part of the NRC's 0350 Panel oversight of licensee improvement initiative E (Closed) Inspection Followup Item 50-461/97006-02: Unusually high range of system flows for acceptance criteria. The acceptance criteria for the design flow rate on the drywell purge (VO) system was specified as 7,320 cfm to 16,270 cfm. The continuous purge (CCP) mode of the VQ system corresponds to the 7,320 minimum value and the containment building ventilation /drywell purge (CBV/DP) mode corresponds to the 16,270 cfm maximum value. However, the testing procedure did not require the licensee to validate the corresponding mode of operation against the acceptance criteri The inspectors reviewed the Updated Safety Analysis Report and noted that the VQ system is not safety-related or required for accident mitigation. The VQ system does provide a backup to the safety-related hydrogen recombiners and can be used to reduce drywell over pressure. VQ isolation valves were supplied with mechanical stops to prevent opening these valves past 50" Blocking the valves ensures that excessive quantities of radioactive materials will not be released via the containment purge syste Following the installation of the mechanical stops, VQ system testing demonstrated that the maximum system flow rate was approximately 12,500 cfm. However, the hcensee did not reduce the maximum allowed acceptance criteria from the design value without the mechanical stops (16,270cfm). The inspectors were concerned that a degraded or nonconforming condition may have existed without recognition by the licensee due to the unacceptably high acceptance criteria. Based on a review of testing data, the inspectors determined that the VQ system flow rates had been maintained below 12,500 cf In response to the inspectors' concerns, engineering personnelinitiated a procedure change to lower the acceptance criteria to a value corresponding to the as built condition of the facility. This item is considered closed based on the inspectors review of test data and engineering personnel's planned revision of the testing procedur . _ . _ _ _ - _ _ _ _ _ _ _ _ ______--______-__ _-_ _ -_-_____- __ _ -__ _ - -

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E (Closed) Inspection Followup Item 50-461/97012-03: Review of feedwater valve performance during reactor pressure vessel hydrostatic test. The inspectors reviewed the results of the hydrostatic test with the cognizant engineer and determined that the i

valves did not exhibit excessive leakage. No additional concerns were identifie E (Closed) Unresolved item 50-461/97015-03: Potential hot short on Division i EDG feed breaker could result in a loss of power to safe shutdown equipment during a control room fire. This unresolved item is a duplicate of LER 50-461/97-021 therefore, a review of the licensee's corrective actions for this issue will be performed as part of the inspectors LER I closecut activitie ,

IV. Plant Support S2 Status of Security Facilities and Equipment S Walkdown of Protected Area Perimeter (IP 71750)

The inspectors performed a walkdown of the protected area perimeter. No discrepancies were note 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 May 28,1998. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified, t

X2 Management Meeting Summary On May 5,1994 e 0350 Panel meeting between the NRC and Illinois Power was held to discuss improve:mhtts in the conduct of operations and the restoration of plant equipment.

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INSPECTION PROCEDURES USED

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IP 37551: Engineering Observations l IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71750: Plant Support IP 71707: Plant Operations IP 92901: Followup - Operations IP 92902: Followup - Engineering IP 92903: Followup - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/98008-01 NCV Enforcernent Discretion: Failure to comply with requirements of TS surveillance requirement 3. /98008-02 NCV Enforcement Discretion: Failure to implement corrective actions regarding verification of primary containment manualisolation valves every 31 day /98008-03 NCV Enforcement Discretion: Failure to follow procedure during calibration of EDG VAR mete /98008-04 NCV Enforcement Discretion: Failure to provide a procedure for safety-related switch gear maintenanc /98008-05 NCV Enforcement Discretion: Failure to implement corrective actions following determination that air operated valve program was inadequat Cicsed 50-461/96-009 LER Failure to perform TS surveillance requirement involving

. verification of secondary containment isolation valve /96009-01 NOV inadequate guidance in NSPS checklist to prevent inadvertent system isolatio /96010-03 IFl Review of vendor recommen-fations regarding recirculation pump seal /96011-01 IFl Potentially nonconservative reactivity manipulation /96015-06 URI Adequacy of licensee's safety function determination progra _ _ - _ _ _ _ _ _ _ _ _ _ -

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50-461/96-017 LER Misinterpretation of time delay relay setpoint data results in Division ill EDG being unable to energize its bus within TS time limi /96412-07 NOV Failure of line assistant shift supervisor to perform adequate turnover to relief operato /96412-20 NOV Failure to properly calibrate Division lli EDG relay resulted in EDG being inoperable for approximately one yea /96412-21 NOV Failure to properly translate design basis information regarding Division til EDG relay into the appropriate procedure /96412-22 NOV Inadequate 50.59 for fuel pool cooling system action pla /96412-23 NOV Inadequate 50.59 for cycled condensate system action pla /96412-24 NOV Inadequate 50.59 for residual heat removal water leg pump action pla /96412-25 NOV inadequate 50.59 for residual heat removal check valve testing action pla /96412-26 NOV inadequate 50.59 for degraded cathodic protection system action pla /97006-02 IFl Unusually high range of system flows for acceptance criteri /97006-03a-g NOV Failure to document MWR job steps, perform steps as directed, i and evaluate risk basis deviation l 50-461/97006-07 URI Failure to account of instrument inaccuracies results in potentially inadequate surveillance procedure j 50-461/97012-03 IFl Review of feedwater valve performance during reactor pressure vessel hydrostatic tes /97015-03 URI Potential hot short on Division i EDG feed breaker could result in a  !

loss of power to safe shutdown equipment during a control room fir j 50-461/98003-05 URI Review of operations department's ability to meet manning requirements specified in emergency plan during a control room fire requiring evacuatio /98-005 LER Failure to verify all primary containment manual isolation devices closed every 31 day r

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50-461/98006-01 URI Adequacy of coatings procedure was questioned due to lack of specified limits for relative huniidity during coatings applicatio /98008-01 NCV Enforcement Discretion: Failure to comply with requirements of TS 3.6. /96008-02 NCV Enforcement Discretion: Failure to implement corrective actions regarding verification of primary containment manualisolation valves every 31 day _ _ _ _ _

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PERSONS CONTACTED Licensee W. MacFarland IV - Chief Nuclear Officer

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G. Hunger, Jri- Plant Manager l W. Romberg, Manager - Nuclear Station Engineering Department-R. Phares, Manager - Nuclear Safety and Performance Improvement I G. Baker, Manager - Quality Assurance J. Goldman, Manager Work Management V. Cwietniewicz, Director - Maintenance W. Maguire, Director- Operations M. Tacelosky, Supervisor - Operations Services

- J. Sipek, Manager - Regulatory Interface

~ J. Place, Director- Plant Radiation and Chemistry l

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LIST OF ACRONYMS l

- CBV/DP Containment Building Ventilation /Drywell Purge Mode

.CCP Containment Continuous Purge  ;

CR Condition Report l EDG Emergency Diesel Generator  !

IFl inspection Followup item LER Licensee Event Report '

MWR Maintenance Work Request OPDRV Operations with the Potential to Drain the Reactor Vessel QA Quality Assurance RHR Residual Heat Removal SGTS Standby Gas Treatment System j TPCL Task Performance Checklist TPD Temporary Procedure Deviation TS Technical Specifications VQ Drywell Purge System >

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