IR 05000155/1996012

Insp Rept 50-155/96-12 on 961130-970117.Violations Noted. Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML20135D446
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	02/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20135D436	List: IR 05000155/1996012 ML20135D434 ML20135D443
References
50-155-96-12, NUDOCS 9703050252
Download: ML20135D446 (19)

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! U.S. NUCLEAR REGULATORY COMMISSION l-REGION lli

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Docket No: 50-155 License No: DPR-06 i

l Report No: 50-155/96012(DRP)

Licensee: Consumers Power Company Focility: Big Rock Point Nuclear Power Plant

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Location: 10269 U.S. 31 North

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Charlevoix, MI 49720 Dates: November 30,1996 - January 17,1997 Inspectors: R. J. Leemon, Senior Resident inspector C. E. Brown, Resident inspector L. N. Tran, Project Manager N. Shah, Chemistry and Health Physics inspector Approved by: Bruce L. Burgess, Chief Reactor Projects Branch 6 l

9703050252 970224 PDR ADOCK 05000155 G PDR

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EXECUTIVE SUMMARY

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{ Big Rock Nuclear Power Plant NRC Inspection Report 50-155/96012

This routine inspection covered aspects of licensee operations, engineering, maintenance, and plant suppor Onerations

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e The plant automatically shutdown due to a loss of turbine generator field causing a j turbine-generator trip without bypass. The inspectors determined that this transient l was within the parameters discussed in the FHSR for a plant shutdown (Section 01.2).

f Maintenance J

e Maintenance and surveillance activities were generally performed well and j accurately documented (Section M1.1).

i j e The licensee correctly diagnosed and repaired the cause of the generator trip, made i procedural changes, and provided training for the operators to safely operate the

{ generator-voltage regulator in manual control. The low-pressure turbine repairs were completed safely and accurately, and the inspectors noted good contractor j control during the work (Sections M1.2 and M1.3).

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o The inspectors identified a work-around associated with source range detector No.

7's failure to reposition. The inspectors also concluded that plant management had j accepted this work-around because of ALARA considerations and was not j documenting the current failures (Section M1.4).

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! e The inspectors identified that a failure to repair a known leak in the roof above the i standby emergency diesel generator resulted in a thin buildup of ice on its batteries j (Section M2.1).

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l * The inspectors identified a violation of 10 CFR 50, Appendix B, Criterion V l

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involving surveillance procedure TV-02, " Containment Integrated Leak Rate Test,"

Rev 28. The procedure was inappropriate to its circumstances resulting in an

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uncontrolled loss of about 400 gallons of reactor coolant and an inline-relief valve

lifting when attempting to pressurize the containment (Section M3.1).

Engineenng j e The inspectors identified an additional example of a violation of 10 CFR 50, Appendix B, Criterion V regarding the lack of acceptance criteria in the maintenance

, procedure for MMSS-1. The procedure did not provide tolerances for reassembling

! the MSIV stem to wedge fit up (Section E1.1).

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l e The licensee maintained a conservative safety focus by deciding to cool the plant '

down to cold shutdown and repack and test MO-7062, emergency condenser loop l No.1 inlet valve, in accordance with the motor operated valve program (Section l E1.2).

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! REPORT DETAILS l

Summarv of Plant Status The plant was operated at full power from the beginning of the period until the plant i tripped off line on December 7,1996, due to a failed voltage control circuit in the turbine- '

generator exciter (Section 01.2). The plant was taken to cold shutdown on December 9, 1996, to allow repacking emergency condenser loop No.1 inlet valve, MO-7062 (Section E1.2). Shutdown activities included retraining the operators on the procedure for operating the turbine-generator in manual voltage control and repacking MO-7062. The

licensee started the reactor on December 11,1996. While warming the turbine, operators detected excessive turbine vibration, indicating that the turbine was out of balance. The plant was returned to cold shutdown on December 13,1996, after additional testing isolated the source of the vibration to the low-pressure turbine. Internal turbine inspection after shutdown revealed that three sections of turbine-blade shrouding were dislodge The plant remained in a forced outage to complete a turbine inspection and to effect repairs for the rest of the inspection period. Additional major work performed included a containment integrated-leak-rate test (Section M3.1) and main steam isolation valve repairs

, (Section E1.1).

1. Operations l

l 01 Conduct of Operations '

01.1 General Comments (71707)

inspection Procedure 71707 was used by the inspectors to conduct frequent reviews of plant operations. Specific events and findings are detailed in the sections belo .2 Reactor 3 cram Caused by Loss of Field Voltaae to the Generator a. Insoection Scone The inspectors reviewed the licensee's response to a reactor trip caused by the loss of turbine generator field voltage. The inspectors interviewed licensee personnel, reviewed operating records, and independently verified plant indication b. Observations and Findinas On December 7,1996, a loss of field voltage to the main turbine generator caused a reactor scram on high power. The inspectors' independent review of the control room panels and recorder traces verified that reactor had tripped on high power, was fully shut down, and had responded as expected. Steam-drum level and plant cool-down rate (less than 100 F per hour) were properly controlled by plant operators.

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The inspectors discussed the plant trip with the control room operators regarding prior indications of voltage control difficulties and actions taken. The operators had t

! noticed that voltage was decreasing, attempted to restore voltage, and called ,

power control for assistance. The operators were preparing to take manual voltage

! control when the reactor tripped.

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The licensee correctly diagnosed and repaired the cause of the generator trip, made procedural changes, and provided training for the operators to safely operate the ,

j generator-voltage regulator in manual control.

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l c. Conclusion

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l The inspectors determined that the plant automatically tripped in response to a loss

of the main turbine generator voltage control and that plant operators had safely

j shutdown the plant.

! 02 Operational Status of Facilities and Equipment

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1 02.1 Enaineered Safety Feature System Walkdowns (71707)

The inspectors used inspection procedure 71707 to walk down accessible portions of the following ESF systems:

e Emergency Diesel Generator e Post-Incident System in all cases, equipment operability, material condition, and housekeeping were acceptable. Several minor discrepancies were brought to the licensee's attention ;

and were corrected. The inspectors did not identify any substantive concerns as a result of these walkdown Miscellaneous Operations issues (92700)

08.1 (Closed) Unresolved item 50-155/94015-02: manual scram due to loss of feed f water. On November 29,1994, with the plant at about 42 percent power, operators were attempting to return one of two condensate pumps to service following repairs. When the equalizing vent to the isolated pump was cracked opal, the air trapped in the pump was immediately introduced to the operating pump via the common-vent line to the condenser. The air caused the operating feed-water pump to trip on loss-of-suction pressure. The control-room operators recognized the loss of the feed pump and tried unsuccessfully to restart it (only one feed pump was available). When multiple attempts to restart the feed pump failed, the operators manually scrammed the reactor. The investigation determined that Standard Operating Procedure (SOP) 15, " Condensate System Hotwell to Reactor Feed Pump," was not adequate for the operating conditions. SOP-15 was initially issued in 1976 after returning a condensate pump to service with the reactor at low power (in 1975), but it had never been field tested for the conditions that existed on November 29,1994. Additionally, the pump shaft packing was replaced with a

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! mechanical seal after SOP-15 was written. This change caused air to be more l l readily trapped within the pump casin {

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The licensee promptly corrected the procedural inadequacies. Correctivs actions  !

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included procedure precautions developed by performing the evolution on the plant

simulator under differing initial conditions. In addition, the return-to-service j l instructions in all of the SOPS were reviewed for similar inadequacies. Training I plans were revised and all the operating crews were retrained following this

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incident. By reviewing selected operating procedures and interviewing different

! operating crews, the inspectors verified that these problems had been corrected.

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. The inspectors determined that, at the time of the event, SOP-15 was not 1 appropriate for the circumstances, constituting a violation of 10 CFR 50, Appendix

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B, Criterion V, " Instructions, Procedures, and Drawings." This licensee-identified

and corrected violation is being treated as a Non-Cited Violation , consistent with j Sociton Vll.B.1 of the NRC Enforcement Poliev(50-155/96012-01(DRP)).

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11. Maintenance j i

1 M1 Conduct of Maintenance

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M1.1 General Comments .

l Insoection Scone (62703) (61726) l l

{ The inspectors followed the troubleshooting efforts following the loss of voltage I

! control to the main generator field and the investigatie.'1 into the cause of excessive

! vibration noted during turbine startup on December 1;,1996. Additionally, the i inspectors observed portions of the following work orders (WO) and surveillances:

Maintenance Actwities

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e WO 12612443: replace moisture separator drain header e WO 12610697: replace valve VRR-34 i e WO 12611276: clean water detector sight glass LS-63-9

e WO 12612277

quarterly battery readings for battery-4 e

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WO 12612276: quarterly battery readings for battery-3 e WO 12610190: monthly battery reading battery-1 1 e WO 12612414: clean turbine parts

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e WO 12612465: cutout turbine drain collector box j e WO 12612413: steam path repairs j e WO 12611209: provide ILRT test support

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I Surveillance Activities i

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integrated leak rate test i e TR-390: MSIV local leak rate test i e TSD-04: core spray full flow test .

! e T7-21: standby diesel generator start and run test i Observations and Findings

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, Maintenance and surveillance activities were reviewed against the FSAR and were  ;

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found to be satisfactorily performed. All observed work was performed with the i

work package present and in active use at the job site. Supervisors and system

engineers monitored job progress, and appropriate radiation control measures were i in place. When questions arose or problems were encountered, the workers i i stopped the activity and discussed the problem with the engineer or supervisor, and action plans were devised to resolve the probleme. Examples included the MSIV

! local leak rate test (Section E1.1), the standby diesel start test (Section M2.1), and the integrated leak rate test (Section M3.1).

j Conclusion

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Maintenance and surveillance activities were generally performed well and j accurately documented. The licensee correctly diagnored and repaired the cause of i the generator trip, made procedural changes, and provided training for the operators i

to safely operate the generator-voltage regulator in manual control. The low-3 pressure turbine repairs were completed safely and accurately, and the inspectors

noted good contractor control during the work. However, some maintenance

, procedure deficiencies resulted in a violation of NRC requirement M1.2 Main Generator Field Voltaae Reoairs

j Insoection Scone i

l Licensee personnel diagnosed and repaired the problem on the main generator after

the plant trip on December 7,1996. The inspectors observed troubleshooting i efforts and maintenance activities related to these repairs.

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l ' Observations and Findinas

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i The licensee determined that a failed resistor in the main generator field voltage l control circuitry was the cause for the loss of voltage. No replacement resistor was l immediately available, so the licensee made a temporary change to System

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Operating Procedure (SOP) 13, " Turbine Generator System," to allow plant startup and provided training for operating the generator in manual voltage control. The

resistor could be replaced with the plant on line. Plant staff had previous

experience and were knowledgeable of the precautions and actions necessary to l'

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l control turbine generator voltage in manual for an extended period of tim However, due to the extended outage caused by problems with turbine blading, the

replacement resistor arrived on site and was replaced during the forced outage.

} Conclusions

j The licensee correctly diagnosed and repaired the cause of a generator trip, made -

i procedural changes, and provided training for the operators to safely operate the i generator-voltage regulator in manual control.

l M1.3 Low.fr.gagge Turbine Repairs l

l Insoection Scope l During the plant startup on December 11,1996, the operators noted excessive

! vibration on the low pressure turbine. The plant was shut down to repair the i turbine. The inspectors observed licensee and contractor personnel troubleshooting efforts and maintenance practices during the repair effor Observations and Findinas The licensee determined that an approximately 1 square-inch piece of metal had dislodged in the outlet of the generator end of the low-pressure turbine, and three sections of turbine-blade shrouding had been knocked off of a section of the moving blades. The licensee performed a complete cleaning and non-destructive testing (NDT) of the low-pressure turbine rotor. The inspectors made the following observations:

e All of the contracted worker's activities were closely monitored by the licensee. Additionally, the contractor orientation included a plant walk-through with a contract coordinator who discussed previous contractor-control issues (IR 50-155/96010 Section R4.1) snd pointed out pertinent plant features to the contractor supervisor e The welding was accomplished with full quality control processes including 100 percent NDT on each weld bea e The inspectors noted that regular and contracted maintenance personnel maintained good foreign material exclusion (FME) practices. Only one instance of foreign materialintrusion was noted. The licensee evaluated the intrusion as not constituting a hazard to plant operation, and the inspectors concluded that no violations of the plant's FME procedure occurred, since the material could not get into the reactor because of the design of the plan e Proper fire protection and radiological control practices were maintained through out the repair effort !

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l Conclusion i

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Low-pressure turbine repairs were performed safely and accurately without damage

to plant components or personnel injury. The inspectors observed good contractor

control during this effort.

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M1.4 Source Ranae No. 7 Detector Failed to insert

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On December 7,1996, source range detector (SRD) No. 7 did not fully insert when

selected by the operator after the reactor scram. The inspectors interviewed l licensee staff, observed plant indications, and reviewed the system description

, manual, chapter 31, " Nuclear Instrumentation System," and the FHSR section

. 7.3.2, Source Range Monitoring.

l Observations and Findinas

After the reactor scram on December 7,1996, SRD No. 7 did not go to the "lN" l position as expected when positioned by the operator with the hand switch. The

inspectors verified that SRD No. 6 and the three channels of DC wide range l monitors were operating properly (indicating reactor power was in the source range)

and were providing required shutdown neutron flux monitoring. The operators

stated that an instrumentation and control (l&C) technician had gone into the

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containment to reposition the detector. The l&C technician entered a high radiation area, pulled on a cable, freed the detector, and then had the operator restart the

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drive motor which repositioned the detector. Technical Specifications required SRD

! No. 7 to be operable before plant startup, but it was not required while shut down.

i j Licensee management stated that failure of an SRD to reposition occurred

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occasionally and that there were no plans to repair the system due to the high cost

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and exposure required to perform repairs. Additionally, the SRDs are not required

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for post accident conditions. A licensee analysis performed in 1993 had

. documented that SRD No. 7 failed to insert six out of eight times. This analysis !

{ concluded that the source range raonitors had been operational when required (for

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startups and refueling activities) and that the repair to the mechanism which moves

the detectors was not effective from an ALARA (as low as reasonably achievable)

! standpoint. At the and of the inspection period, no CR had been written for the

, failure of SRD No. 7 to reposition.

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! The inspectors identified a work-around with SRD No. 7's failure to reposition. The

, inspectors also concluded that plant management had accepted this work-around j because of ALARA considerations and was not documenting the current failures.

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t f M2 Maintenance and Wiatorial Condition of Facilities and Equipment

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i l M2.1 Standhv Dianal Generator Failure to Start (617261 l

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On January 8,1997, the (non-safety related) standby diesel generator (SBDG) l

? failed to start. The inspectors interviewed licensee staff, and reviewed I

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documentation including: test procedures, battery voltage and specific gravity :

i graphs, a condition report, and the FHS I

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f Observations and Findinas  !

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On January 8,1997, the standby diesel generator failed surveillance T7-21,  !

" Standby Diesel Generator (SBDG) Start and Run." The SBDG failed two attempted I

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starts before suspending the surveillance tes l

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l A licensee inspection determined that the failure to start was due low battery i voltage. Additionally, the licensee found a thin coat of ice' on the batteries due to '

i the low ambient temperature and leaking SBDG trailer roof. The following day, the l 1 inspectors inspected the trailer during a diesel run and found similar conditions. No 1 l action had been taken to correct the deficiencies. The maintenance manager.sent a l l worker out to clear the snow off the trailer roof and make temporary repairs to the 1' leak. On January 15,1997, the inspectors inspected the trailer and determined i

! that the temporant roof repairs were adequat I i

l The maintenance records on the SBDG batteries showed that voltage and specific f 1 gravity had been lower after each start, but the system engineer was not aware of i 3 the trend until the inspectors requested the information after the SBDG failed to l l start. A condition report, CR 95-BRP-707, written by plant engineering in 1995, ;

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recommended that the SBDG runs be extended in cold weather to allow enough I time for the battery to recharge, but operations had not extended the diesel run

. time.

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The inspectors concluded that since the SBDG was already on site there were no l violations of NRC requirements related to the commitment to have a SBDG available j within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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c. Conclusion j

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The inspectors concluded that licensee corrective actions were inadequate; .

however, because this diesel is not required to operate to mitigate camage to the i

reactor, no violations of NRC requirements were identified. The condition of the l 4 SBDG trailer had deteriorated to the point of allowing ice to form on the batterie The SBDG weekly runs used more battery power than was restored, but the battery i

readings were taken monthly and trended at the discretion of the system engineer.

l Additionally, an earlier recommendation to extend the SBDG run time had not been '

implemented, i

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M3 Maintenance Procedures and Documentation l

l M3.1 Contamment integrated Leak Rate Test (61726)

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Due to the expected duration of the forced outage to repair the turbine, the licensee

performed the scheduled April 1997 containment integrated leak rate test (ILRT) on

January 2,1997. The inspectors observed preparation and performance of Big

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Rock Point Surveillance Procedure TV-02, " Containment integrated Leak Rate

Test," Revision 28. The inspection included a review of applicable portions of the i

final hazards summary report (FHSR), the plant technical specifications (TS), and 10 l CFR 50, Appendix J.

! Observations and Findinas

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j The number and types of sensors in containment met the requirements of 10 CFR 4 50, Appendix J, and the data was collected and processed properly. The ILRT

[ results met the procedural requirements, indicating that the total leakage met the l TS required maximum weight-percent per day value. However, two procedural

} deficiencies were noted in TV-02:

i i 1) Step 5.1.a, required the operators to depressurize the nitrogen side of all i

control rod drive accumulators, but did not give instructions on how to l accomplish this. The operator accomplished this by u.ing the steps in

standard operating procedure (SOP) 30 which isolates and depressurizes the j accumulators for personnel protection during maintenance. SOP-30 left the i accumulator drain valve and nitrogen vent valve open to prevent possibly re-j pressurizing the accumulator. After discussing the valve position with the shift supervisor, the operator left the vent and drain valves open because that would be their required position when recharging the accumulators after i the ILRT was complete. The valve position was not recorded on the status

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A temporary change had been approved by the plant review committee to

! insert a manual scram signal into the reactor protection system before

! isolating instrument air to the containment (TV-02, step 5.1.ao.1). When i the manual scram was inserted, approximately 400 gallons of water was drained from the primary system to the containment sump via the accumulator drain valves before the control room operators noticed decreasing steam drum water level and corresponding increasing dirty sump water level and took actions to stop the coolant leak from the primary syste ) On January 2,1997, while attempting to pressurize the containment for the ILRT, a relief valve on the filters in the containment charging line lifted and no air entered the containment. Investigation revealed a blank flange installed in the first flange connection outside VCl-1, sphere test isolation

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! valve, which is welded to penetration H-80. TV-02, step 5.2, " Maintenance

Test Preparation," part "a", stated, " Remove blank flange from sphere

pressurizing line inside containment, penetration H-80." However, TV-02 did

! not include a step to remove the blank flange from outside containment on i j the sphere pressurizing line, H-80. No record of a blank flange being

installed outside VCl-1 on penetration H-80 existed, but the previous ILRT

! restoration required the installation of blank flanges inside and outside containment on the sphere pressurizing line, H-80. Revision 28 of TV-02

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contained the same requirements. Additionally, no attachment to TV-02 l was provided to illustrate the normal and the test configuration of the blank

flanges on penetration H-80 similar to Attachment 9, " Penetration H-77 j Configuration."

The inspectors noted that the blank flange had not been re-installed outside l penetration H-80 as required by TV-02, step 5.13.d, after completing the ILRT. An

engineer told the mechanics that a blank flange installed on the external end of the l containment charging line (outside the extemal penetration room) was the second j blank flange; however, TV-02 had not been revised to clarify the exact intended i location for the H 80 external blank flange. Additionally, an opening exists in the piping between the blank flange outside the building and the flange next to VCl-1.

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' Conclusions

! The ILRT results met the maximum weight-percent per day value in accordance

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with technical specifications and 10 CFR 50 Appendix J. However, failing to provide explicit instructions on how to depressurize the CRD accumulators, failing l to ensure the removal of the blank flange installed outside penetration H-80 were

two examples of a violation of 10 CFR 50 Appendix B, Criterion V, " Instructions, j Procedures, and Drawings" (50-155/96012-02A,B(DRP)).

MS Miscellaneous Maintenance issues (92902)

b i l M8.1 (Closed) Unresolved item 50-155/94013-01: unanticipated diesel fire pump i automatic start. During a refueling outage, the diesel fire pump (DFP) was tagged 3 out for alignment checks and maintenance. When the work was complete on the DFP, the shift supervisor (SS) authorized clearing the personnel protection tags and ;

performing surveillance tests to ensure operability. The maintenance procedure did not specify how to position the electrical supply breaker, so the SS decided to leave l the breaker open until the correct position could be verifie !

While the DFP was tagged out, a separate event involving a dropped fuel bundle (discussed IR 50-155/94013, Section 2.4.2) occurred. The SS was involved in completing the corrective actions to allow continuing fuel movements and had an operations supervisor assigned to aid in running the shift. The SS had determined 1

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that a caution tag should be placed on the DFP stating that the supply breaker was open, but the SS got distracted by other actions and forgot to direct the tag to be hung. The status of the breaker was not turned over to the next shift. After shift turnover, an auxiliary operator (AO), who was continuing to run surveillances on the j

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DFP, came to a point in the procedure which required the control switch to be in the " AUTO" position. The AO called the SS office, but the operations supervisor answered. The operations supervisor remembered that the switch had to be in AUTO to run an auto-start surveillance and gave permission for the AO to put the switch in AUTO. The DFP immediately started, as designed, due to sensing a loss of power to the reactor depressurization system cabinet. Immediate corrective actions included stopping all outage work, forming a high level investigative team to determine the root cause, and recommending long term corrective action The corrective actic, team found that the SS had been tasked with too many actions, that the breaker status had not been turned over to the on-coming shift, and that maintenance procedures did not specify how to position the breaker, as operations procedures did. Appropriate changes were made to correct this problem in all maintenance procedures. Additionally, operator aids were developed to clearly show the status of all plant components and management held a stand-down to train the operators on the changes before outage work was resume The inspectors determined that, at the time of the event, the maintenance procedures used, I-FPS-7 and I-FPS-8, were not appropriate for the circumstances, constituting a violation of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings." This licensee-identified and corrected violation is being treated as a Non-Cited Violation , consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-155/96012-03(DRP)).

Ill. Engineering i

E1 Conduct of Engineering '

E Lack of rbantitative Sr=cifications to Renair the &!n Steam Isalation Valve i Inanaclim.Sc.one On October 3,1994, and December 19,1996, main steam isolation valve (MSIV),

MO 7050, failed local-leak-rate testing (LLRT). A contributing factor for the failures was the lack of adequate tolerances and fit-up between the T-slot in the valve wedge and the valve stem tee. The inspectors reviewed valve drawings, valve work history, completed work requests, and maintenance procedures and held discussions with the maintenance staff and a contracted valve exper Observations and Findinas Main steam isolation valve (MSIV), MO-7050, a containment isolation valve, failed j its local leak rate test on October 3,1994, and December 19,1996 after the volve '

wedge had been replaced in 1994 due to a crack in one of the seating surface After the MSIV leak rate test failure in December 1996, the licensee had a valve j i

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l- expert present during disassembly and troubleshooting of the failure of the valve to

, seal. A blue-check of the valve wedge and seat indicated that the valve did not

. fully close. The MSIV has failed the as-found LLRT after each run since the valve l wedge replacement performed in November,1994.

l l The licensee and the valve expert found that too little clearance existed between ;

the valve wedge T-slot and the toe on the valve stem and determined that the lack i

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of clearance was a contributing factor to the MSIV failing the LLRT.- The valve

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manufacturer provided the licensee with information specifying the correct clearance on January 10,1997.

The valve wedge and stem are normally sold as a matched set from the

manufacturer, who machines the clearances in the T-slot in the wedge to ensure a

proper fitup between the T-slot and toe on the valve stem. In 1994, the licensee ,

i replaced the valve wedge and valve stem without ensuring the clearance '

l requirements between the valve wedge T-slot and the valve stem toe were met.

j The inspectors determined that this information was not contained on any of the

MSIV valve drawings in the work package or written in MSIV maintenance

procedure MMSS *, " Inspection and Repair of Main Steam isolation Valve MO-  ;

7050," Revision 4, dated September 23,1993. Additionally, replacing the valve

! stem was not discussed in the work history; however, it was indicated as being j replaced on material issue ticket 8094922, dated November 11,199 j i

Conclusion y

! The inspectors determined that when the stem and wedge were replaced, neither maintenance procedure MMSS-1, Rev 4, nor work order (WO) MSS 12412294

, specified fitup clearances between the wedge T-slot and the stem tee. Failure to

{ include appropriate qualitative and quantitative acceptance criteria was a violdtion j of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings" (50-155/96012-02C(DRP)).

E1.2 Management Discussion to Renack the Emeroency Condenser Loon No.1 Inlet ya[ve MO-7062 a. Insoection Scone inspection Report 150/96010(DRP), Section 02.1 and M2.1 discussed the packing  ;

leak on the emergency condenser inlet valve, MO-7062, and the licensee placing '

the valve on the backseat to stop the steam leak. The inspectors attended the PRC meeting for plant startup on December 9,199 Observations and Findinos j MO-7062 was open on its backseat to prevent leakage past the stem pack lng. The valve had not been operated electrically; therefore, there was a question if it would close electrically if needed to isolate a leaking tube bundl i

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] . -

] The licensee concluded that the safety function of this valve was to open and that

, MO-7062 was in its safety-related position. However, SOP-6, " Emergency Condenser System," required the valve to be closed from the control room to

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isolate a leaking tube bundle. Additionally, the licensee planned to maintain this

valve in the motor operated valve (MOV) program which would require operating the valve electrically off the backseat. The valve would then leak. The plant was

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still in " Power Operation," (defined as "any operation other than shutdown or cold

shutdown with the reactor vessel closure bolted in place"). .The plant temperature

! was 350 'F and - if the PHC determined that the status of MO-7062 was

, satisfactory - the plant could be started up. However, to repair MO-7062, the j plant would have to be cooled down.

$ Management decided to take the plant to cold shutdown, replace MO-7062's valve i

stem packing, and test MO-7062 in accordance with the MOV program.

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c. Conclusion i -

The inspectors concluded that the plant management displayed a good safety focus !

j by deciding to cool the plant down to cold shutdown and repack and test MO-i 7062, emergency condenser loop No.1 inlet valve, in accordance with the motor

! operated valve program.

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IV. Plant Suncert

j R1 Radological Protection and Chemistry (RP&C) Controla l

j R 1.1 General Comments l Using inspection Procedures 71707 and 71750, the inspectors made frequent tours

of the radiologically protected area (RPA) and discussed specific radiological j controls with the ALARA coordinator and various radiation protection (RP)

I technicians. The inspectors observed plant conditions and licensee performance l including radiation protection practices and extensive work within the turbine repair

radiologically controlled boundaries.

The inspectors concluded that the licensee was following good ALARA and i

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radiation protection practices and performed contamination control practices when working on the turbin S1 Conduct of Security and Safeguards Activities

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S1.1 Security (71750) (71707)

! l

! The inspectors monitored the licensee's security program during routine activities I

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and tours to ensure that the approved security plan was being implemented. The inspectors noted that personnel within the protected area displayed proper photo-l identification badges and individuals requiring escorts were properly escorted (there were several contract personnel escorted during this outage). The inspectors also f 15

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observed that personnel and packages entering the protected area were searched by appropriate equipment or by han V. Management Meetings

X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 3,1997. The licensee acknowledged the findings presente The licensee did not identify any of the documents or processes reviewed by the l inspectors as proprietar !

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i FARTIAL LIST OF PERSONS CONTACTED  ;

i Licensee  !

l P. Donnelly, Plant Manager j R. Addy, Assistant Plant Manager j S. Beachum, Systems and Project Engineering Manager

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K. Pallagi, Chemistry / Health Physics Manager G. Boss, Operations Manager D. Hice, Maintenance Manager G. Withrow, Plant Safety and Licensing Director l l l

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INSPECTION PROCEDURES USED IP 37551: Engineering

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IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems

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IP 61726: Surveillance Observations IP 62703: Maintenance Observation IP 64704: Fire Protection Program IP 71707: Plant Operations i

IP 71750: Plant Support Activities i IP 73753: Inservice inspection IP 83729: Occupational Exposure During Extended Outages i

IP 83750: Occupational Exposure l IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

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Facilities

IP 92902

Followup - Engineering

IP 92903: Followup - Maintenance d

ITEMS OPENED and CLOSED Opened 155/96012-01 NCV OPS Procedure inappropriate for the Circumstances 2 155/96012-02 VIO Three Examples of a 10 CFR 50, Appendix B, Criterion V l Violation j 155/96012-03 NCV Maintenance Procedure inappropriate for the Circumstances Closed a

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155/94013-01 URI Review of DER-BRP-94-102 Re Diesel Fire Pump Start 4 155/94015-02 URI Manua Scram Due to Loss of Feedwater

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155/96012-01 NCV OPS Procedure Inappropriate for the Circumstances 155/96012-03 NCV Maintenance Procedure Inappropriate for the Circumstances i

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a LIST OF ACRONYMS USED

ALARA As Low As Reasonably Achievable A Auxiliary Operator l CARB Corrective Action Review Board f

CFR Code of Federal Regulations DFP Diesel Fire Pump j DRP Division of Reactor Projects

EDG Emergency Diesel Generator ESF Engineered Safety Feature

! FHSR Final Hazards Summary Report

. H Health Physics

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IFl Inspection Followup Item

IP inspection Procedure IPE Individual Plant Evaluation IPTE Infrequently Performed Test and Evolution j IR Inspection Report i LCO Limiting Condition for Operation LER Licensee Event Report

, NCV Non-Cited Violation NOV Notice of Violation

>

NRC Nuclear Regulatory Commission

RDS Reactor Depressurization System

RO Reactor Operator

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RP Radiation Protection

. RPA Radiologically Protected Area

~; SFP Spent Fuel Pool SS Shift Supervisor SV Solenoid Valve TS Technical Specification UE Unusual Event j URI Unresolved item i VOTES Valve Operation Test Evaluation System

. VIO Violation WO Work Order

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