IR 05000461/1989018

Safety Insp Rept 50-461/89-18 on 890512-0707.Violations Noted.Major Areas Inspected:Previous Insp Findings,Onsite Followup of Written Repts,Allegation Followup,Operational Safety Verification & Monthly Maint Observation

ML20247N702
Person / Time
Site:	Clinton
Issue date:	07/18/1989
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20247N684	List: IR 05000461/1989018 ML20247N678 ML20247N694
References
50-461-89-18, CAL-RIII-89-16, NUDOCS 8908030123
Download: ML20247N702 (19)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-461/89018(DRP)

Docket No. 50-461 License No. NPF-62 Licensee: Illinois Power Company f00 South 27th Street lecatur, IL 62525 Facility Name: Clinton Power Station Inspection At: Clinton Site, Clinton, Illinois Inspection Ccnducted: May 12 through July 7,1989 Inspectors: P. Brochman P. Hiland S. Ray W. Grant Approved By: M. A. Ring, Chief Sh Reactor Projects Section 3B U

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Inspection Summary Inspection on May 12 through July 7, 1989 (Report No. 50-461/89018(DRP))

Areas Inspected: Routine, unannounced safety inspection by the resident inspectors of licensee action on previous inspection findings; onsite followup of written reports; allegation followup; operational safety verification; monthly maintenance observation; monthly surveillance observation; onsite ,

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followup of events at operating reactors; engineered safety system walkdown; enforcement conference; and management meetin Results: Of the seven areas inspected, two violations were identifie Fne was in the area of followup of previous inspection findings concerning unsealed electrical conduit penetrations in the secondary containment. The other was in the area of operational safety verification and included three <

examples of inadequate control of Technical Specification requirements during

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changes in OPERATIONAL CONDITIONS which resulted in missed surve111ance In addition, two " licensee-identified" violations were discussed in the area of operational safety verification concerning two Leak Detection system instruments that were improperly calibrated and one train of Main Control Room Ventilation being inoperable due to missing hardware required for seismic qualificatio None of the findings were considered to have a major safety significance. All were receiving management attention although the inspectors determined that the finding of unsealed secondary containment penetrations did not receive management attention in a timely manne PDR l

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ADOCK 05000461 )

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! DETAILS L

I Personnel Contacted Illinois Power Company (IP)

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1. W.~Kelley, CE0'

l #L. Haab, President l *#D. Hall, Senior Vice President *#@J. Perry, Assistant Vice President

• 1. K. Baker, Supervisor, I&E Interface

• 1. @R. Campbell, Manager, Quality Assurance

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J. Cook, Manager, Nuclear Planning and Support

• 1. @R. Freeman, Manager, Nuclear Station Engineering Department

• 1. S. Hall, Director, Nuclear Program Assessment

• 1. @D. Holtzcher, A; ting Manager, Licensing & Safety

1. @J.' Miller, Manager, Scheduling & Outage Management

1. J. Weaver, Director, Licensing

• 1. J. Wilson, Manager, Clinton Power Station

1. R. Wyatt, Manager, Nuclear Training Soyland

• J. Greenwood, Manager, Power Supply Nuclear Regulatory Commission

1. B. Davis, Regional Administrator, Region III

1. P. Brochman, Senior Resident Inspector, Clinton

1. E. Greenman, Director, Division of Reactor Projects, Region III

@J. Grobe, Director of Enforcement, Region III

1. @J. Hickman, Project Manager (Clinton), NRR

1. P. Hiland, Senior Resident Inspector, Clinton/ Perry

@R. Knop, Chief, Reactor Projects Branch 3, Region III

@C. Paperiello, Deputy Regional Administrator, Region III

1. J. Partlow, Associate Director for Projects, NRR

@R. Paul, Office of Investigations Field Office, Region III

• 1. @S. Ray, Resident Inspector, Clinton

1. @M. Ring, Chief, Reactor Projects Section 3B, Region III

@ Denotes those attending the enforcement conference on June 14, 198 # Denotes those attending the management meeting on June 16, 198 * Denotes those attending the monthly exit meeting on July 7, 1989.

The inspectors also contacted and interviewed other licensee and  !

contractor personne ;

1 Previously Identified Items (92702) i (Closed) Violation (461/88009-02J: Failure to Perform Containment Airlock Leakage Tes _ _ _ _ _ - _ _ - _ _ _ _ .

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.This event was previously discussed in Inspection Report No. 50-461/88009, Paragraph 5.b. The licensee responded to the violation in Letter U-601221 dated July 8,1988. The licensee also reported the event as LER 88-014. The inspectors reviewed the licensee's corrective actions including training records for

appropriate personnel, and surveillance test results. During this event, the inspectors identified a deficiency with the surveillance test procedure for t.he airlock leakage test. The procedure allowed the licensee to conduct preliminary partial tests and make repairs before taking the actual surveillance data. Thus no'"as found" data would have been available. The inspectors. verified that the licensee revised the airlock leakage test procedure to eliminate the preliminary tests. The licensee also revised a similar test

. procedure for the drywell airlock. This item is close (Closed) Violation (G /88021-01): Failure to Take Prompt Corrective Action to Ensure That Revisions to Valve and Electrical Lineups Were Performe This issue was previously discussed in Inspection Reports No. 50-461/87020, Paragraph 10.b.(3), No. 50-461/87030, Paragraph 9.b.(1), and No. 50-461/88021, Paragraph 2.a. The licensee responded to the violation in Letter U-601292 dated October 18, 198 That letter discussed the licensee's plans to improve the programmatic controls on the valve and electrical lineup program. The inspectors reviewed the licensee's actions which included the issuance of Operations Standing Order (050) 200 to implement a tr eking system for Operations Support to track completion of e: *alve and electrical lineups. The inspectors

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also reviewed v.'..incrative Procedure CPS No. 1005.03, Revision 12, which instituted a ti?cking system for the Procedure Control Cente Other administrative p mcedures, memoranda, and training records were also reviewed to verify that the program for control of valve and electrical lineups was adequately instituted. The inspectors verified by discussions with appropriate personnel in the operations support staff and direct field observations of system lineup files and lineup change tracking records that revisions to valve and electrical lineups which were required to be performed upon issuance were being promptly performe The majority of the revised lineups were performed within a day or two after issusnce. Delays in the performance of revised lineups were due to plant conditions. This item is close (Closed) Unresolved Item (461/89014-05): Missing Internal Conduit Seals on Secondary Containment Penetration This item was discussed in Inspection Report No. 50-461/89014, Paragraph 5.e. The item was left unresolved pending the inspectors'

review of licensee's actions to determine the cause and extent of the unsealed penetrations. The licensee had a previous history of problems with improper installation of electrical penetrations through the secondary containment gas control boundary as discussed in Inspection Report No. 50-461/89014. In this case, the inspectors

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noted that the licensee had not reported the unsealed conduits as an LER nor-had they expanded the scope of the corrective actions beyond the five penetrations identifie The inspectors encouraged the licensee to revisit the issue in light of a previous similar event that was reported as LER 89-006-00 and to look for additional unsealed penetrations in similar areas of the secondary gas

- control boundar The licensee subsequently determined that the condition was-reportable as an LER because Technical Specification 1.3 defines SECONDARY CONTAINMENT INTEGRITY as existing when: The sealing mechanism associated with each secondary containment penetration, e.g., welds, bellows to 0-rings, is OPERABL Thus l SECONDARY CONTAINMENT INTEGRITY had not existed since initial plant l operations ~on September 29, 1986, until the seals were installed on l April 14, 1989. The licensee submitted LER 89-023-00 dated June 29, 1989, to document the event.

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The inspectors attended a licensee critique on June 20, 1989, in which the event was discussed and corrective actions determine The licensee determined that the Shift Supervisor who originally reviewed the condition report on the missing conduit seals on April 10, 1989, had incorrectly determined that the condition was not reportable as a Technical Specification violation because he believed that the secondary containment did not become " unsealed" until a hole was drilled in the junction box into which the unsealed conduits entered. In addition, no root cause and generic corrective action was pursued for the event because the Manager-Nuclear Station Engineering Department incorrectly downgraded the quality significance

[ of the condition report based on the fact that secondary gas control boundary inleakage was within Technical Specification limits even with the seals not installe After the critique of the event, in which the inspectors again suggested that the licensee review other similar electrical <

penetrations in the secondary containment, the licensee pursued )

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a root cause and generic corrective action program. The licensee determined that four additional electrical conduit penetrations were undocumented and warranted inspection. All four were found to have missing internal penetration seals. The four seals were installed on June 24, 198 The inspectors agreed with the licensee's determination that the l l actual safety significance of the unsealed conduits was small based on several surveillance tests which have demonstrated that secondary containment inleakage was less than Technical Specification limits and the Standby Gas Treatment System was able to perform its design ,

function with the existing leakage. However, the inspectors found I that Operating, Engineering, and Quality Department personnel did not properly evaluate and disposition the identified secondary containment breeche This allowed a Technical Specification violation to go undetected, unreported and uncorrected for over j

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two months aft'er the' condition was initially cocumented on April 10, 1989.. In addition, the licensee's responsiveness to the NRC's

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concerns over the' deportability and. generic corrective actions was not aggressive. The inspectors brought the concern to licensee

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management's attention.during an exit interview on May.12, 1989,.

but the licensee did not critique the event and determine the facts-of the issue until June 20, 198 The failure of the licensee to maintain SECONDARY CONTAINMENT INTEGRITY as specifiec by Definition 1.38.e in accordance with the requirements of Technical Specification 3.6.6.1 during. operations

'in OPERATIONAL CONDITIONS 1, 2, and 3, when irradiated fuel was being handled in the secondary containment, and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel, all of

.which occurred during the period between September 29, 1986,.until June 24, 1989, is a violation (461/89018(DRP)). Unresolved Item 461/89014-05.is. closed and upgraded to a violatio One' violation was identified in this are ~ Onsite Followup of' Written Reports (92700) (Closed)'LER 87-033-00 (461/87033-LL): Violation of the Plant's Technical Specifications Due to a Deficient Valve Lineup Procedur :This issue was a precursor to the larger problems with valve and electrical lineups as documented in Violation 461/88021-01. That violation was closed above in Paragraph 2.b. The inspector's review of the corrective actions for that violation were adequate to close the related LER 87-033-00. This item is close (Closed) LER 87-065-00 (461/87065-LL): Reactor Trip From Unexpected Loss of Instrument Air During Power Supply Transfer Surveillance Due to Inadequate Procedure and Untimely Operator Respons This event was previously discussed in Inspection Report Ho. 50-461/87036, Paragraph 11.b.(5). Corrective actions included l revising Surveillance Procedure CPS No. 9080.09 to add a caution to expect the isolation of instrument and service air system containment isolation valves during the surveillance. Other similar surveillance procedures were also to be reviewed to see whether similtr cautions needed to be added. In addition, the problem regarding simultaneous illumination of the open and closed indicating lights for the inboard instrument air containment isolation and outboard drywell isolation I valves needed to be resolve The inspectors reviewed revisions to' Surveillance Procedures CPS E No. 9080.09 as well as related procedures 9080.03 and 9080.07 to verify that the required cautions had been incorporated.

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The inspectors also reviewed completed Maintenance Work Request C44237 l'

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L to verify that the dual indication problems had been corrected. The problem was corrected by reversing the leads to the neon bulbs under Engineering Change Notice 9197. This-item is close (Closed) LER 88-014-00 and LER 88-014-01 (461/88014-LL and 461/88014-LL): Loss of Containment Integrity Due to Inadequate Assessment of the Impact of an Airlock Repair During Post Maintenance Testing Evaluatio This item was previously discussed in Inspection Report No. 50-461/88009,- Paragraph 5.b. The violation that was issued as a result of the event was closed above in Paragraph 2.a. Corrective actions for the violation were essentially the same as for the LER and were reviewed at the same time. This -item is close No violations or deviations were identifie . Allegation Followup

' Closed) Allegation (RIII 89-A-003): In an anonymous allegation received by the NRC Region II2 Office of Investigations, an individual contended that (a) on or about January 5,1989, two or more cases containing radioactive' material were received at the Clinton Power Station from General Electric (GE) without any markings or labeling and may have been shipped to Clinton without the required identification on the shipping papers and, (b) that on January 7, 1989, the reactor vessel head was moved without both required radiation monitors in operatio Discussion: The allegations were originally referred to the licensee for resolutior A NRC radiation specialfst conducted a followup review of the licensev i investigations. In letter dated March 30, 1989, which referred the allegations to the licensee, the NRC requested that the licensee, when investigating items for allegation (a) and twothese allegations, specific items foraddress three allegation b). sp(ecific The items for allegation (a) were: [1] what methods were used to bring contaminated / radioactive GE equipment onsite; [2] during the shipment of GE equipment to the Clinton site, were DOT regulations adhered to; and [3] if any significant problems existed in the aDove areas, what corrective actions are planned. The items for allegation (b) were: [1]

what radiation monitors are required to be operational during movement of the reactor vessel head; and [2] if any of the above monitors were not operational what corrective or compensatory actions were taker,. In a letter of response, dated May 23, 1989, the licensee stated that they had investigated the allegation and did not substantiate it. however, this letter did not provide sufficient substantiating inforr:ation concerning the licensee's investigation and a telephona call was required to gather additional data. Discussed below are the licensee's findings and additional observations of the NRC inspector, The licensee's investigation confirmed that contaminated equipment was received onsite on January 5,1989, and in accordance with procedures was moved to the radiologically controlled area (RCA). Interviews of GE radiation protection supervisors and personnel involved with moving 6 l

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l the shipping containers indicated that the equipment inside the cases was surveyed; however, they could not confirm that the surveys were documented -as required by procedure. A licensee review of the shipping documentation prepared by the shipper (GE) indicated that the containers were shipped in accordance with DOT regulations and were properly marked

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and labeled. Radiation levels detected by the shipper and noted on the

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00T package label were '5'mR/hr and 2.5 mR/hr at contact, respectively, en each shipping container. Licensee interviews with the personnel involved with the receipt and moving of the equipment indicated that the shipping containers were clearly idercified as radioactive material. The-L . contractor responsible for conducting the radiation survey of the equipment and for documenting it is no longer onsite. Licensee radiation protection (RP) technicians were counseled on the_importance of documenting radiation surveys and forwarding survey results to the RP Shift Supervisor. RP Shift Supervisors were reminded of the importance of ensuring that radiation survey results are sent to the records storage facility. The licensee supervisor responsible for supervising the RP contractor activities was counseled on the need to ensure that contractors fulfill licensee requirement The licensee's investigation of the reactor vessel head move on January 7,1989, determined that although two radiation monitors were not operable, the Clinton Power Station Technical Specifications (TS)

were not violated. One of two noble gas activity stack monitors was inoperable, but the other one was operable, and per the TS only one was required to be operable. Also, the new Fuel Storage Vault area monitor was _not operable, but in accordance with the TS action statement, area surveys of the monitored area were being performed with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A review of'TS by the inspector confirmed the licensee's actions were as require Findings: The NRC's review of the licensee's investigations indicated they were adequate to demonstrate that the allegations were not

. substantiate No violations or deviations were identifie . Operational Safety Verification (11707)

The inspectors observed control room operations, attended selected pre-shift briefings, reviewed applicable logs, and conducted discussions with control room operators during the inspection period. The inspectors verified the operat'ility of selected emergency systems and verified tracking of LCOs. Routine tours of the auxiliary, fuel, containment, control. diesel generator, turbine buildings and the screenhouse were ,

conducted to observe plant equipment conditions including the potential '

fur fire hazards, fluid leaks, and operating conditions (i.e., vibration, !

process parameters, operating temperatures, etc). The inspectors verified that maintenance requests had been initiated for discrepant conditions observed. The inspectors verified by direct observation and discussion with plant personnel that security procedures and radiation protection (RP) controls were being properly implemente _ - _ - . l

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' Inspections were routinely' performed to' ensure that.the licensee conducted activities at the facility' safely and in conformance with regulatory

. requirements. .The inspections focused on the implementation and overall

. effectiveness of the licensee's control'of operating activities, and the

. performance of licensed and nonlicensed operators'and shift-technical advisors. .The following items were considered during'these. inspections:

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. Adequacy of plant staffing and supervisio . Control, room professionalism, including procedure adherence,

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.. operator attentiveness and response to alarms, events, and L off normal condition . Operability of selected _ safety-related systems, including attendant' alarms, instrumentation, and control Maintenance of quality records and report During the' inspection period the plant operated in various OPERATIONAL '

CONDITIONS and power levels. On May 22, 1989, the reactor was brought'

-critical after- the completion of the'first refueling outage which had begun on January On May 26, the operators manually scrammed the reactor from 19% due to problems controlling Reactor Vessel level with the Motor Driven Feedwater Pump Feed Regulating Valve (IFW004). On May

.27 the reactor was brought critical following troubleshooting of IFWOO On June 1 the reactor was manually scrammed from 2% power due to problems a- with IFW004. The reactor was in the process of being shutdown as a result of.a Reactor Recirculation (RR) pump seal failure. The seal

' failure and 1FW004 problems were discussed in a Special Team Inspection

Report No. 50-461/89021. On June 19, the reactor was brought critica following repairs to the seal and 1FW004. It was shutdo n again fo~ several hours shortly after criticality due to problems with-leak detection instrument calibrations and was restarted again later on June 19. On June 28, the reactor automatically scrammed from 100% due to a failed sudden pressure relay on the main transformer. On June 30, the reactor was brought critical following replacement of the sudden pressure rela At the conclusion of the inspection period the plant was operating normally at near full powe On May 21, 1989, the licensee identified that they had missed a required technical specification surveillance to compensate for inoperable reactor coolant system continuously recording conductivity monitors. On Mare,h 30, 1989, the continuour conductivity monitor installed on the Reactor Recirculation system was declared inoperable due to a cracked cell. On May 21, 1989, with the plant in OPERATIONAL CONDITION 4, the Reactor Water Cleanup (RWCU) system differential flow instruments became inoperable which required that the RWCU system be isolated in accordance with Technical Specification 3. 'The Shift Supervisor failed to realize that isolation of RWCU also caused the only other continuous conductivity monitoe to become inoperable. Technical Specification 4.4.4.c.1 required that when no continuous conductivity monitors were available in OPERATIONAL

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CONDITIONS l', 2, and 3, in-line conductivity' measurements be taken at least once per four hours. -The plant entered OPERATIONAL CONDITION 2 at 1:53 p.m. on May 21. Thus an in-line sample was due by at least 5:53 p.m. At approximately 7:00 p.m., chemistry technicians noted that the RWCU conductivity monitor was inoperable. An in-line sample was taken at 7:50 p.m. with satisfactory results. Thus the plant had been-in violation of the Technical Specifications for approximately two hour The licensee reported the event as LER 89-021-00 dated June 20, 1989. The cause of the event was attributed to failure of the Shift Supervisor to identify that isolation of RWCU would make the associated conductivity monitor inoperable. Poor communications between the Shift Supervisor and Chemistry personnel and failure to promptly repair the Reactor Recirculation conductivity monitor also contributed to the event. This event is considered an example of a violation concerning inadequate control of Technical Specification Surveillance and ACTION requirements during changes in OPERATIONAL CONDITIONS and other applicable conditions-(461/89018-02a(DRP)).

b. On June 9, 1989, the Division I Emergency Diesel Generator experienced a slow start during a post maintenance test. The diesel took 12.2 seconds to reach rated speed and voltage instead of the required 12 seconds. Initially the Shift Supervisor determ u i that the event would require a report to the NRC within 30 days in accordance with Technical Specification 4.8.1.1.3 which required that all Diesel Generator failures, valid or non-valid, be reporte Further evaluation by the system engineer determined that the start was not i reportable because the cause of the slow start was determined to be a

" fuel availability" problem due to draining down of the fuel lines during the maintenance. Because the fuel lines were drained, rolling the engine was necessary to prime the lines and the start was not actually a " start attempt" that was expected to be successfu Condition Report No. 1-89-06-035 was initiated to document the investigation. The Condition Report was not dispositioned by the end of the inspection period and the inspectors were unable to verify the system ergineer's determination. This event is considered an Unresolved Item (461/89018-03) pending the inspectors' review of the licensee's disposition of the Condition Report.

I c. On June 19, 1989, the licensee identified that twc instruvant; in the leck detection system were not in calibration. During tho performance

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of the shif tly chann91 checkt, the operators noted that Reactor Water Cleanup (RWCU) pump rcom 1 temperature instrument IE31-621A eppeared to be failed low. The room temperature had been graduaily increasing i due to plar.t startup over the past day but since that instrument

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indicated 50 degrees Fahrenneit when failed low, the failure had oct been noticed until the difference between the failed instrument and ,

its OPERABLE mate reached about 30 degree About two hours later, i it was noted that RWCU heat exchanger room temperature instrument 1E31-620A was also failed low. It was determined that both instruments had been last calibrated by the same technician so a l

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reactor shutdown was ordered as a conservative measure until the status of the leak detection instruments could be determined. The L reactor had just been made critical at the time, and rods were reinserted to shut it dow The licensee determined that the two instruments discussed above were the only ones affected and the only ones that had been calibrated by the particular technician. The instruments were recalibrates and the "as found" data indicated that they were both reading about 40 e

degrees low. It was determined that the technician had improperly positioned a switch on the test equipment used in the. calibratio The calibration procedure was unclear about the proper switch position. Corrective actions accomplished before restarting the plant included clarifying the calibration procedure, recalibrating the two failed channels, conducting channel checks on all other Riley temperature detectors, checking the calibration of three other randonoy selected Riley detectors, and providing more definite channel check ccceptance criteria for Riley temperature detector i The corrective actions were completed later the same day (June 19)

I and the plant restarte The inspectors found the actions described above to be conservative and in accordance with regulations. The problem with non-specific acceptance criteria has been discussed previously and contributed to a previous violation discussed in Inspection Report No. 50-461/88004, Paragraph 5.a. The licensee developed interim guidance in Plant Manager Standing Order -050 but had not developed further guidance.

. Although the two instruments had been inoperable for longer than the l required ACTION time limits in Technical Specification Table 3.3.2-1 l by the time they were discovered, because of the licensee's conservative and aggressive corrective action, and the low safety significance, the event was considered a " licensee-identified" violation (461/89018-03) for which a Notice of Violation was not issued in accordance with 10 CFR 2, Appendix C, Sectior; V.G.I. This item is closed. The licensee intended to issue an LER to report the event. The corrective action for the LER will be reviewed when it is issue {

l l c. On June 22, 1989, the licensee identified that they had missed a j l required Techn'ical Specification Channel Functional Test Surveillance {

on the Rod Pattern Control System Pod Withdrawal Limit High Power <

Setpoint the previous day. Technical Specification Table 4.3.6-1

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Notation (c) required that the channel functional test be condu::ted as each power range above the rod pattern control system low power setpcint is entered for the first time during any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period dcring power increases or decreases. The plant had been conducting a power increase and had gone above the low power setpoint at 7:23 on June 21. Operating Procedure CPS No. 3004.01, " Turbine Startup and Generator Synchronization," Step 8.2.10 called for the operatora ,

to conduct the Low Power Setpoint Channel Functional Test at that l point but failed to instruct them to also conduct the High Power Setpoint Channel Functional Tes i l

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Similar. events'were previously reported by the licensee in-LERs 87-051-00 and 88-031-00. .LER 87-051 was considered part of a violation (461/87032-01) discussed in Inspection Report

~No. 50-451/87032, Paragraph LER 88-031 was'considared a .

licensee identified violation of. minor safety significance for which no Notice of Violation was issued. -Corrective actions.for the LERs and; violation . included procedural changes to clarify the requirements for and provide reminders for performing the channel functional tests. The licensee's. investigation for the event determined that-the procedural changes were incomplete in'the case'of CPS No; 3004.0 The. missed surveillance was discovered and.successfully performed;'

before the plant exceeded the-High Power Setpoint so the safety ,

significance of the. missed test was small. The licensee intended.to report the event as an LER. Failure of the licensee to perform the required. channel functional test of the Rod Withdrawal Limit High Power Setpoint is considered an example of.a violation concerning

inadequate control.of Technical Specification Surveillance and .

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- ACTION requirementsiduring changes in OPERATIONAL CONDITIONS and other applicable. conditions (461/89018-02b(DRP)).

~ ~ On June 26,.1989., the 1icensee identified that they had missed

required Technical Specification Channel Calibration Surveillance

=on the Average Power Range Monitor Flow Biased Simulated Thermal Power - High and Neutron Flux - High requirement of Table 4.3.1.1- The calibrations were required prior to entry into OPERATIONAL CONDITION 1 but due to confusion in the Notations of Table 4.3.1.1-1 in'the Technical Specifications and inadequate procedures, the surveillance were not accomplished. The surveillance were not listed as being required on Operating Procedure CPS No. 3002.010002,

" Mode 1 Checklist," and Surveillance Procedure CPS No. 9431.60,

" Average Power Range Monitor (APRM) Gain Adjustment and Setpoint Verification," which contained the steps for performing the channel calibration, but-which did not list entry into OPERATIONAL CONDITION 1-as a trigger for the procedur The licensee was investigating possible previous cases of missing the same requirements and intended to report the findings in an LE The channel calibrations cre also required ta be done weekly in- 1'

OPERATIONAL CONDITIOK Ic therefore, the total time that instruments could be out of calibration after a startup was limited to a week.

l Thus the safety significance of the missed survei14nce was smal '

Failure of the licensee to perform the required channel calibrations l is considered an example of a violatir.n concerning inadequate contrcl 1 of Technical Specification Surveillance and ACTION requirements.during changes in OPERATIONAL CDNDITIONS and other applicable conditions I

(461/89013-02c(DRP)). On June 29, 1989, the licensee determined that the "B" train of Main Control Roam Ventilation (VC) had been inoperable due to control i relays not being seismically mounted. The condition was originally identified on April 3, 1989, during the performance of Maintenance

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Work' Request (MWR) D06524 for calibration of.a timer relay in the VC'

chiller control-circuit. The. technician performing the work noted that, the common mounting screw for relays OKY-VC623B and OKY-VC6248

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was missing. MWR D03903 to. install the missing screw was initiated

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on April:11, '1989 and was completed on May. 17, 198 On May 17, the system engineer reviewing the MWR noted that no-Condition Report had been initiated when the MWR'was written to j investigate the possible seismic inoperability of the systeir. due n to the missing screw. Ha initiated. Condition Report 1-89-05 084

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atlthat time.- On June'29, Nuclear Station Engineering Departmen (NSED)' determined that the relays had not been seismically qualified while'the mounting screw was missing. On. June 28, NSED determine ,' 'that the "B" VC system may not have been able to' perform its design function if the relays. failed. On June 29,.1989, Licensing and Safety Department initiated revision 1 to. Condition Report No.'l-89-05-084 to initiate issuance of the required LER.and root

.cause;and generic corrective action determinatio Technical Specification'3.7.2 required that two independent VC systems be OPERABLE in all OPERATIONAL CONDITIONS and when irradiated fuel-is being handled in the' secondary containment.' Failure of the a licensee to maintain the'"B":VC system OPERABLE due to a missing?

relay mounting' screw in the chiller control circuit was considered a

" licensee-identified" violation (461/89018-04) for which a Notice of Violation'was not issued in accordance with 10 CFR 2, Appendix C, Section V.G.I. NSED determined that.the_ missing-screw would have affected the "B" VC trains ability to start after a-seismic even If it was already running, the missing hardware would not have affected its performance. There was no affect on the redundant 100%

capacity "A"~VC train. Thus the safety significance of the finding was smal This item is closed. The inspectors will review the root cause and corrective actions for the LER when issue One violation with three examples was identified in review of this are Two additional violations were identified for which a Notice of Violation was not issued in accordance with 10 CFR 2, Appendix C, Section V. '

' MonthlyMaintenancpObservation{62703_1 Salected portions of the plant maintenance activities on safety-related systems and componynts were observed or reviewed to ascertain that the actMties were perforsned in accordance with approved procedures, regulatory guides, industry codes and standards, and that the performance of the' activities conformed to the Technical Specifications. loe inspection included activities associated with praentive or cr<rrectivt

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maintenance of electrical, instrumentation and contral., mecnanical equipmeot, and. systems. The following items were considered during these inspections: the limithg conditions fer operation were met while components or systets wert, rer oved from service; approvals were obtained

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t prior to initiating the work; attivities were accomplished using approved procedures and were inspected as applicable; functional testing and/or

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calibration was performed prior to returning the components or systems to service; parts and materials that were used were properly certified; and appropriate-fire prevention, radiological, and_ housekeeping conditions

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were maintaine The' inspectors observed / reviewed the following work activities:

Maintenance Work Procedure N Activity D14022 Acoustic Monitor Troubleshooting D14075- 1FW004 Troubleshooting VX Chiller Troubleshooting / Repair Severa' additional maintenance activities were observed by other NRC inspectors during this period including a Special Team Inspection documented in Inspection Report No. 50-461/8902 No violations or deviations were identifie . Monthly Surveillance Observation (61726)

An inspection of inservice and testing activities was performed to ascertain that the activities were accomplished in accordance with applicable regulatory guides, industry codes end standards, and in conformance with regulatory requirement Items which were considered during the inspection included whether adequate procedures were used to perform the testing, test instrumentation was calibrated, test results conformed with Technical Specifications and procedural requirements, and tests were performed within the required time limits. The inspectors determined that the test results vere reviewed by someone other than the personnel involved with the performance of the test, ar.d that any deficiencies identified during the testing vere reviewed and resolved by appropriate management personne The inspecters observed / reviewed the fo)1owing activities:

Surveillance / Test j Procedure N Activity __ _ _ , _

CPS No. 3080.01 Diesel Generator Operability j a

CPS No. 9439,30 Untested Island Calibration d i

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CPS No. 9432.17 RWC0 Hi Temp Cnannel Functional

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Several additional surveillance activities were observed by other )'

! NRC inspectors during this period including a Special Team Inspection I documented in Inspection Report No. 50-461/8902 ;

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r4 No violations or deviations were identifie . Onsite Followup of Events at Operating Reactors (93702) General The inspectors performed onsite followup activities for events which occurred during the inspection period. Followup inspection included one or more of the following: reviews of operating logs, procedures, condition reports; direct observation of licensee actions; and interviews of licensee personnel. For each event, the inspectors reviewed one or more of the following: the sequence of actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant procedures and license conditions; and verification of the nature of the event. Additionally, in some cases, the inspectors verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective action Details of the events and licensee corrective actions noted during the inspectors' followup are provided in Paragraph b belo Details (1) Automatic Start of "B" Residual Heat Removal Pump On May 16, 1989, i.he licensee experienced an automatic start of the "B" Residual Heat Removal (RHR) pump during a surveillance procedure. The start occurred when a logic card was reinserted into its normal position following testing. The pump was stopped by the control room operator within a few seconds of the start. Although the pump start was not part of a preplanned evolution, the licensee determined that the start was not reportable as an automatic actuation of an Engineered Safety Feature in accordance with 10 CFR 50.72. The licensee detemined tnatnotthe start signal and an start signalCore Emergency wasCooling simply System the normal pump)

(ECCS i actuation signal. The associated valve repositioning and i annunciators that would have indicated an ECCS signal did not occur. The inspectors agreed that the determination that the i pump start was not reportable was reasonabl I J

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(2) Manual Screm From 19% Power due to Reactor Vessel Level Control

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On May 26, 1989, the licensee reported to the HRC via the ENS that they had manually scrammed the reactor frcm 19% due to problems controllir.g reactor vessel level. The problems were the result of a failure of the Motor Driver. Ft.edwater Pemp Feed RegulatingValve(IFW004). Details of the event were discussed in Inspection Report No. 50-461/8902 . _ _ _ _ _ _ _ _ - _

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(3) Notification of Unusual Event and Alert due to Recirculation Pump Seal Failure Resulting in Reactor Coolant System Leakage Greater than 50 GPM On June 1, 1989, the licensee informed the NRC via the ENS of a Notification of Unusual Event due to unidentified reactor coolant system leakage greater than 5 gpm. The event was later upgraded to an Alert when the leakage increased to over 50 gp Details of this event were discussed in Inspection Report No. 50-461/8902 (4) Manual Scram From 2% Power due to Reactor Vessel Level Control Problems On June'1, 1989, the licensee reported to the NRC via the ENS that they had manually scrammed the reactor due to problems with controlling reactor vessel level which resulted from a failure of~1FW004. The inspector was in the Main Control Room during the scram and determined that operator actions and equipment response to the scram was proper. Details of this event were discussed in Inspection Report No. 50-461/8902 (5) Entering Technical Specification Required Shutdown Action Statement due to Failure of the Switchgear Heat Removal System On June 20, 1989,. the licensee informed the NRC via the ENS that they had entered a Technical Specification Action Statement which required that the plant be in Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. During a flow balancing evolution being conducted on the Division II Switchgear Heat Removal System (VX), the chiller unit tripped on high oil temperature. The chiller was subsequently restarted for troubleshooting but tripped on high oil temperature again. The Shift Supervisor then declared the Division II VX system inoperable and instituted emergency repair The VX syctem is nut addressed in Technical Specifications but it was a required support system for several Technical Specification systems. The operating staff reviewed Technical Specifications and determined that the most restrictive Limiting Condition for Operation was 3.8.2.1 for DC electrical power sources. The Division II 125 volt battery and 125 volt full capacity battery charger were cooled by the inoperable chiller in the esse of a loss of offsite power or soae other problem with the normal nonsafet.y-relattd cooling systeL Thus the Shif t SLpervis,or dedared the Division II DC system inoperable and carrted out ACYION a e,f the specification which required that the division be restered within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least HOT SHUTD0VN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> , - __ _ _ - --_

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When the VX chiller was not repaired within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the Shift Supervisor made the ENS notification. In about another 90 minutes the VX system.was restored by adding Freon and successfully-

' tested. The shutdown action statement was exited before any actual reduction in power. The plant was operating at about 1% power throughout the even The inspector was in the main control room or at the chiller for the duration of the event and monitored the licensee's action. The problem with VX and other support systems relating to the proper handling of Technical Specification Limiting Conditions for Operations had been previously discussed with the licersee on several occasions. The inspectors observed that the licensee's handling of this event was timely, conservative, and prope Further clarification of the deportability of the event as the " initiation of any nuclear plant shutdown' required by the plant's Technical Specifications" is discussed below in Paragraph 8.b.(7).

(6) ' Automatic' Reactor Scram from 100% Power due to Failed Main Power Transformer Sudden Pressure Relay On June 28, 1989, the licensee reported to the NRC via the ENS that they had experienced en automatic reactor scram from 100%

power. The scram was the result of a main generator trip due to a sensed sudden pressure in the "C" phase of the main power transformer. The sudden pressure signal also initiated the transformer deluge syste The licensee's investigation determined that the root cause of the event was corrosion of the sudden pressure relay electrical components. The corrosion was believed to be due to moisture buildup in the relay housing. The licensee replaced the relay and housing with an improved model which included provisions for venting moisture. They alto replaced similar relays on the other two phases of the main power trar,sformer and the emergency reserve auxiliary, and unit auxiliary transformers 4 before starting up on June 30, 1989. They replaced the relays I on the reserve auxiliary transformer shortly ofter the startu '

(7) Entering Technical Specification Required Shutdown Action Statement due 'to Failed Surveillance on Jet Pump Operability On July 1, 1989, the licensee reported to the NRC via the ENS that they had entered a Technical Specification Action Statement which required that the plant be in Hot Shutdown within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> With the plant operation at about 60% power, the licensee was performing a surveillance procedure on jet pump operability in accordance w'.th Techr.ical Specifii.ation 4.4.1.2.a. When the surveillance hiled, tho shift Superrisor declared the jet pumps inoperable and centered the ACTION statement for Technical Specification 3.4.1.2 which required that the plant be in at least HOT SHUTDOWN within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> _ _ _

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w It was believed that the reason for the surveillance failure

"' was that the data was taken while power was being increased i

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and control rods were being moved.- The surveillance'was j J immediately reperformed with stable plant conditions and passed '!

successfully. Thus'the licensee reported that'they had been in ;

the; shutdown' ACTION' statement for only about 45 minutes and no ,

factual;powerreductionwasaccomplighe i Alth'ough~r'eporting'short' entries into shutdown ACTION l statements with.no actual power reduction was conservative, ;

the inspectors consulted;with regional management and informed <

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..the licensee that an' ENS notification in accordance with 10:CFR 50.72 for'"the initiation of any nuclear p'lant shutdown i required by the plant's Technical Specifications was not !

required unless; (1) an' actual reduction in power;or insertion l of control rods was initiated; or (2) there was indication that ;

the problem would not be corrected in time and the initiation ;

F of an actual shutdown was expecte 'I No violations or deviations were identifie ;

i . Engineered Safety System Walkdown (71710)

The inspectors performed a walkdown of the Division I Diesel Generator  ;

(DG) and associated support systems during the report period to verify )

the system status. Support systems included Fuel Oil-(D0), Lubr.icating i Oil, Starting Air, Shutdown Service Water (SX), Essential Switch;; ear Heat

, Removal (VX), and Diesel Generator Room Ventilation (VD). At the time of the walkdown, the licensee had identified the Division I DG as an l 0PERABLE Engineered Safety Feature System meeting all the requirements of i the plant's Technical Specification j For the purposes of the walkdown, the inspectors utilized the current revisions of the system's valve, instrument, arid electrical lineup checklists, operating and' surveillance procedures and piping and instrumentation drawing CuriN the walkdown, the following discrepancies were noted:

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Yhn lubricating oi'l strainer cover was not installed on the 12'

cylinder engine. The inspectors immediately informed the Line Assistant Shift Supervisor who ordered the cover to be installed and-initiated Condition Report 1-89-05 .072 to-document the discrepanc The switch described as the " Voltage Regulator Control Switch" in Electrical Lineup CPS No. 5506.01E001 is labeled the " Generator Voltage Control Switch." Divisions II and III were labeled properl Valve 2DG157,had no labe . .. .

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Isolation valves were installed for Crankcase Lockout Pressure Switchen 1PS-DG-062C and 063C but were not listed in the Instrument Valve Lirieup CPS No. 3506.01V002. The inspectors observed that the valves were open at the time of the walkdow The inspectors determined that the discrepancies noted above did not affect system operability, No violations or deviations were identifie . Enforcement Conference On June 14, 1989, Illinois Power Company management met with the NRC

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Region III management (denoted in Paragraph 1) at the. regional office The purpose of the meeting was to allow the licensee to present its findings relating to a potential violation concerning allegations discussed in Office of Investigation Report No. 3-86-008. Addendum 1 contains the outline of the issues raised by the NRC in the meeting and the licensee's presentation. During the meeting, certain discrepancies between information provided to the NRC and to the licensee by certain individuals became evident. The NRC requested that the licensee provide

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copies of records of their interviews of the individuals' for the NRC's revie . Management Meeting (30702)

On June 16, 1989, Illinois Power Company senior managemert met with the NRC Region III management (denoted in Paragraph 1) at the Clintcn Power Station. Among the topics discussed in the meeting were the currert plant status, personnel and organizational changes, the security personnel strike, and major work accor.plished and deferred in the recent refueling outage. The licensee also presented their findings, ccrrective actions, and future plans for the failed RR pump seal, failed feedwater regulttinn valve, and tripped drywell chiller discussed in Confirmatory

' Action Letter CAL-RIII-89-016. NRC pianagement acknowledged the information and the Regional Administmtor agreed to allow the plant to startup. This authorization and the NRC's understandings were confirmed in a lttter from the Regional Administrator dated June 21, 198 . Violations For Whicn A " Notice of Violation" Will Not Be Issued The NRC uses tha Notice of Viclation as a standard method for formalizing the existence of a violation of a legally binding requirement. ilowever, because the NRC vants to encourage and support Itcensees' initiatives far self-ider.tification anc correction of problems, the NRC will not generally issue a Notice of Violation for a violatior, that meets the tests of 10 CFR 2. Appendix C,Section V. These tests are. O ) the violation was icentified by the licenset; (2) the violation would be categorized as Severity level IV or V; O) the viclation cas reported to '.he NRC, if required; (4) the violation vHI be corrected, including measures to i prevent recurrence, within a reasonabla time periou; and (5) it was not a violation that could reasonably be expected to have been prevented by the l

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licensee's corrective action for a previous violation. . Violations of regulatory requirements identified during the inspection for which a thtice of Violation was not. issued were discussed in Paragraphs and . Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations. An unresolved item disclosed during this inspection was discussed in Paragraph . Exit Meetings-(30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

throughout the inspection and at the conclusion of the inspection on July 7,.1989. The inspectors summarized the scope and findings of the inspection activities. The licensee acknowledged the inspection finding The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any documents / processes as proprietar The inspectors attended exit meetings held between regional / headquarters based inspectors and the. licensee as follows:

Inspector Date S. Ray (Special Team) June 23, 1989

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P. Reschesk June 29, 1989 T. Ploski June 29, 1989

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