IR 05000354/1989002

Safety Insp Rept 50-354/89-02 on 890124-0313.Violation Noted.Major Areas Inspected:Operations,Radiological Controls Maint & Surveillance Testing,Emergency Preparedness,Security & Engineering/Technical Support

ML20248J192
Person / Time
Site:	Hope Creek
Issue date:	03/31/1989
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20248J180	List: IR 05000354/1989002 ML20248J176 ML20248J187
References
50-354-89-02, 50-354-89-2, IEB-85-003, IEB-85-3, IEB-88-007, IEB-88-7, NUDOCS 8904140350
Download: ML20248J192 (12)

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l U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No.

50-354/89-02 License NPF-57 Licensee:

Public Service Electric and Gas Company P. O. Box 236 Hancocks Bridge, New Jersey 08038 Facility:

Hope Creek Generating Station Dates:

January 24, 1989 - March 13, 1989 Inspectors:

G. W. Meyer, Senior Resident Inspector D. K. Allsopp, Resident Inspector Approved:

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3i P. D. Swetland, Chief Date /

Reactor Projects Section 28

Inspection Summary:

Inspection 50-354/89-02 on January 24, 1989 - March 13, 1989 l

Areas Inspected:

Resident safety inspection of the following areas:

operations, radiological controls, maintenance & surveillance testing, emergency preparedness, security, engineering / technical support, safety assessment / assurance of quality, and Licensee Event Report and open item follow-up.

Results: The inspectors concluded that a violation existed due to the uncontrolled electrical jumpers installed in the drywell equipment drain pump controls, which bypassed a pump protective interlock. An Executive Summary follows.

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EXECUTIVE SUMMARY

. Hope Creek Inspection Report 50-354/89-02 January 24, 1989 - March 13, 1989 Operations: A violation was issued for two electrical jumpers installed in the drywell equipment drain pump controls for over ten months without the required administrative controls in place. The inspectors concluded that control room operators' actions and responses during the reactor shutdown and.startup for

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the mid-cycle outage and during the inadvertent LOCA signal actuation were timely and effective. The inspectors reviewed a technical clarification provided by reactor engineering regarding the instability region of the power to flow map and found it to be acceptable.

Several housekeeping items identified in the. diesel generator room were promptly corrected.

Radiological Control: The inspector observed an unacceptable application of-protective clothing (lab coat over shorts) and concluded it was an isolated case.

PSE&G is taking action to resolve an inconsistency between stations regarding personnel frisking and hard hats.

Maintenance / Surveillance: An Unresolved Item was issued for PSE&G's identifi-cation of.four containment isolation valves oriented (by design) such that quarterly localLleak rate tests do not measure the valve stem leakage. An apparent logic tester malfunction resulted in an inadvertent actuation of the B channel LOCA signal. An inadequate procedure resulted in an inadvertent alternate rod insertion (ARI) while shutdown.

The inspector found previously undiscovered maintenance problems of air bubbling into the torus through the torus water cleanup return line and a stem packing leak on the RCIC steam supply isolation valve; corrective maintenance was initiated.

Emergency Preparedness:

Routine inspection did not fino anything noteworthy.

i Security:

Routine inspection did not find anything noteworthy.

Engineering / Technical Support: The PSE&G response to Supplement 1 of NRC Bulletin 85-03 (motor-operated valve switch settings) was found to be acceptable.

Safety Assessment / Assurance of Quality:

The violation for the uncontrolled electrical jumpers demonstrated the need for continued management attention to preventing uncontrolled modifications of the plant.

PSE&G's identification of the above containment isolation valve design issue and the initiation of corrective actions were commendable.

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DETAILS 1.

SUMMARY OF OPERATIONS Hope Creek entered this report period at full power and' continued power operations until February 18, when the unit was shut down to begin the mid-cycle outage. Outage work included removal of three control rod drives (CRDs) using the remote handling equipment, installation of a bypass line around the reactor water cleanup (RWCU) heat exchangers, inspection and cleaning of the feedwater flow venturis, modification of Rosemount trans-mitters, repairs to service water piping, and inservice inspection of reactor coolant system piping.

On February 21 a faulty logic tester caused a spurious actuation of the B channel of the Loss of Coolant Accident (LOCA) signal and its associated equipment.

On February 22 an inadvertent actuation of the Redundant Reactivity Control System (RRCS) occurred due to errors in removing instrumentation channels from service.

On March 5 the reactor was restarted and on March 6 the generator was synchronized to the grid. However, turbine load could not be increased above 30 MWe due to a failed load set motor, and the generator was sub-sequently removed from the grid.

Following motor replacement the generator was resynchronized to grid and loaded on March 7.

2.

OPERATIONS (71707,71710,25588)

2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.

Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions witF personnel, independent verification of safety system status and Limiting Cor.aitions for Operation, and review of facility records.

These inspection activities were conducted in accordance with NRC inspection procedure 71707.

The inspectors performed 255 hours0.00295 days <br />0.0708 hours <br />4.21627e-4 weeks <br />9.70275e-5 months <br /> of normal and back shift inspection including weekend and holiday inspection on:

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February 11, 1989 8:00 a.m. - 2:00 p.m.

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February 19, 1989 2:15 p.m. - 8:15 p.m.

Februa ry 20, 1989 10:55 a.m. - 4:55 p.m.

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March 12, 1989 8:30 a.m. - 2:30 p.m.

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2.2 Inspection Findings' and Sign'ificant Plant Events i

A.

On. February 5, PSE&G determined that two electrical jumpers had_ not been properl.y controlled, in that the jumpers were installed to. bypass

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I an interlock on the drywell equipment drain' pumps.and-had remained in place for over ten months without anyone's knowledge. The interlock

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i prevents the two equipment drain pumps from-running.if a discharge l

isolation valve is shut. With the limit' switch.jumpered' out, this l

pump protection was removed, but the pumps. responded properly to start commands (based on sump level), and thus pump operability was not'

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. degraded.

The jumpers were initially installed on March 24, 1988, when both-equipment drain pumps did not start due to a' failed open'11mit switch.

A work order (WO) was initiated to replace the failed open limit switch. The operators requested controls technicians to install the-jumpers to bypass the pump ' interlock and permit pumping 'down the equipment drain tank. The controls technicians installed the jumpers under the administrative control of a jumper log (for troubleshooting less than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />).

Procedure SA-AP.ZZ-13, Control of Temporary.

Modifications specifies that such jumpers be removed within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> apr the administrative controls for.a temporary modification must be implemented.

However, the jumper log sheet.was mistakenly assigned to another WO associated with a Design Change Package (DCP) on the-sumps, instead of the W0 corresponding with the failed limit switch.

This jumper log'was inserted into and maintained with the DCP.

Later, the DCP was unsuccessful and was withdrawn (not closed out) by Engineering and Plant Betterment. Since the DCP was not officially closed out, it did not go through a formal closure, and the open jumper log was not identified.

However, this would have only.provided earlier detection of an improperly controlled jumper. The inspector concluded that the root cause of the problem was that the jumpers'

were installed without an effective,' timely administrative control.

The technical significance of the jumpers was minimal, in that the drywell equipment drain sump continued to perform its design function.

However, uncontrolled modifications of the plant could potentially degrade the plant in a significant way. Also, the inspector noted that two instances of poor jumper control on November 10 and 19,1987 were cited as a violation in Inspection Report 50-354/87-23. The inspector concluded that the corrective actions for that' violation were inadequate to prevent this recurrence, and as such, this occur-rence would be cited as a violation, despite being found by plant personnel. Accordingly, this instance of in-adequate control of electrical jumpers is an apparent violation (354/89-02-01).

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i B.

The inspectors evaluated the actions of. control room personnel durin'g various evolutions,~ including the reactor shutdown and restart associated with the mid-cycle outage and the inadvertent actuation of'

the B-channel LOCA signal during core spray system testing (described in Section 4.3.B).

The inspectors concluded that the operators'

actions and responses were. timely and effective, that communications were accurate and concise, and that the personnel worked well as a team.

Specifically, during the inadvertent actuation the operators promptly. determined the problem and restored the unit to a normal lineup in a timely manner.

C.

In response toLNRC Bulletin 88-07, operating procedures'have been revised to address potential power. oscillations at low core flows.

The inspector reviewed a ' reactor engineering technical clarification, which addressed core flow less than natural circulation flow.' The Bulletin and the revised procedures did'not address this condition, because it is'not' physically'possible.

However, indications of this.

condition may occur at Hope Creek in single recirculation loop operation when the operating recirculation pump speed is approximately 48% or less. At these speeds natural circulation forces in the.

inactive loop overcome the reverse flow normally induced from-the active loop at higher pump speeds. The core flow measurement includes negative flow circuitry to compensate for the reverse flow of single loop operation. This compensation is incorrect at the' lower single loop flows. The current negative flow circuitry.is not designed to j

accommodate this situation, but PSE&G is evaluating methods to provide

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more accurate core flow adjustment circuitry for this condition. 'The-inspector concluded that the clarification which clearly excludes' the subject power-to-flow region from the instability concern was accurate and acceptable.

D.

During the plart walkdown portion of an' operator licensing examination-(NRC Inspection Report 50-354/89-04), the inspector noted several housekeeping issues in the diesel generator rooms. These issues included two valve number tags which had become detached from their respective valves, and several drain line caps which had not been reinstalled. Also, numerous valve locking tabs and tools were found-lying on the floor.

These items were promptly corrected when brought to the PSE&G's attention.

3.

RADIOLOGICAL CONTROLS (71707)

3.1 Inspection Activities PSE&G's compliance with the radiological protection program was verified on a periodic basis. These inspection activities were conducted in accordance with NRC inspection procedure 71707.

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3.2 Inspection Findings and Review of Events A.

The inspector observed an equipment operator removing tags in a contaminated room with skin exposed between his overcoat and booties; he had on short pants. Although Radiation Protection Department procedure RP-T1.ZZ-202 allows access to mildly contaminated areas with an overcoat and booties over street clothes, the inspector judged this protective clothing to be unacceptable.

The equipment operator had shifted to shorts to dress out in full protective clothing'when he was advised by radiation protection personnel that an overcoat and booties would be sufficient.

The equipment operator proceeded to the work site, donned the overcoat and booties over his shorts and entered the contaminated room with his legs partially exposed. Operations and Radiation' Protection supervision agreed that this clothing was unacceptable and initiated corrective action, which will include instruction of all equipment operators and technicians that this protective clothing approach is unacceptable.

The inspector concluded that this incident represented an isolated case of poor judgement regarding protective clothing and that while the inspectors will continue to monitor this area, no further NRC action is warranted at this time.

B.

Salem requires employees to remove and self-frisk their hard hat, which then does not enter the Betamax frisker with the individual for final frisking.

Hope Creek does not require a self-frisk of the hard hat, rather the hard hat is removed from the head and monitored with the individual during the Betamax frisking. The inspector questioned PSE&G as to why Salem and Hope Creek had different hard hat frisking requirements for exiting the radiological control area (RCA).

Since many employees work at both stations, the inconsistent frisking requirements have caused some confusion.

Radiation Protection supervision informed the inspector that they had been aware of this inconsistency and that a consistent approach had been agreed upon between stations.

Specifically, both stations will require that hard hats remain on during the Betamax frisking of the front side and be removed prior to Betamax frisking of the back side.

This method will enable a thorough frisk of the hard hat and the head.

The new method will be implemented prior to the Salem 1 outage in mid-April.

The inspector concluded that this corrective action was acceptable and appropriate.

Personnel frisking practices will continue to be reviewed.

C.

On March 1, 1989, an incident occurred in which two technicians received minor internal contamination while working on a valve in the drywell.

The follow-up of this incident was performed by a regional specialist and is documented in Inspection Report 50-354/89-05.

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4.

MAINTENANCE / SURVEILLANCE TESTING (62703,61726,64704)

4.1 Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved proce19res, Techrical Specifications, and appropriate industrial codes and standards.

These inspection activities were conducted in accordance with NRC inspection procedure 62703.

Portions of the following activities were observed by the inspector:

%'/, Order Procedure Description MD-CM. B F-009 Control Rod Drive.(CRD)

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Disassembly and Decontamination MD-CM.BF-001 Removal and disassembly of CRD MD-PM.BF-008 30-39 881212112 MD-CM.KJ-012 Replacement of head gasket on A diesel generator 890224007 MD-GP.ZZ-003 Repair of purge valve to torus The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance program.

4.2 Surveillance Testing Inspection Activity

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The inspectors performed detailed technical procedure reviews, witnessed ir progress surveillance testing, and reviewed completed surveillance packages. The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulations.

These inspection activities wee conducted in accor-i dance with NRC inspection procedure 61726.

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The following surveillance tests were reviewed, with portions

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witnessed by the inspector:

OP-ST.SN-001 Test lifting of M safety relief valve (SRV)

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OP-ST.BE-003 Time response functional test (18 Months) of core

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spray loop 'd i

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L OP-ST.BH-002l Functional test (18 Month) of SLC pump

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IC-SC.BB-077E. Calibration of reactor vessel narrow range level

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transmitter M7-ILP-03H Local leak rate testing of torus penetration P-219

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IC-FT.SE-014-Functional test.of APRM B IC-FT.BB-026 Functional' test of-reactor vessel high pressure

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M9-1SV-27H Ultrasonic inspection of recirculation and feedwater

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. welds The surveillance testing activities inspected were effective with respect

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to meeting 'the safr / objectives of the surveillance testing program.

4.3' Inspection Findings A.

On March 3 testfag personnel associated with the local leak rate e

! sting of-penetration P-220, which includes the torus purge supply

' piping and its two associated containment isolation valves, noted that the inboard valve was oriented such that the stem of the valve (a 24' inch butterfly valve) was on the torus side of the seating

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This orientation resulted in the leakage from the valve stem being tasted during the integrated containment leak rate test.

but not being tested during.the quarterly local leak rate test.

Further PSE&G review found that-four of six similar valves had such orientations and that the valves had been' oriented in accordance with the original design.

PSE&G initiated expedited design evaluations to enable measurement of these leakages to support the planned outage restart on March 5.

However, because of the numerous design constraints.on these valves and limited accessibility, the potential solutions were complicated

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and not clearly achievable.

In addition, PSE&G found that high I

quality packing material was installed around the. applicable valve

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stems and that no adjustments to these packings had been made sub-sequent to the mo,t recent containment integrated leak test.

Based on the inspector's research, this issue is known to apply to numerous boiling water reactors (CWRs) and has existed for years.

No specific guidance on resolution of the generic issue has been produced by the NRC, as yet. Accordingly, the inspector concluded that an expedited, short term fix was not necessarily in the best interests of public health and safety. With Region I management concurrence, the inspector informed Hope Creek that given the condition of the stem packing and

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the current test method would be. acceptable pending resolution of this

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issue. ~PSE&G instituted additional, administrative controls;to prevent-

- packing adjustment and will pursue an appropriate.long term resolution of the' periodic local leak rate testing of the stem. packing following restart-from the outage.

This issue represents an Unresolved Item (354/89-02-02);

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On February 21 with the reactor in a cold shutdown condition, a. test'

equipment problem resulted in a spurious actuation of the low low reactor vessel level (LOCA level 1) signal.

This caused initiation of parts of the Primary Containment Isolation System (PCIS), starting of'two recirculation fans and a' vent fan of the Filtration, Recir-culation, and. Ventilation System (FRVS), an initiation signal for B core spray pump, an initiation signal for the B diesel generator, and other LOCA signal actuations.

The spurious signal resulted when an ECCS._ logic tester was disconnected from the B core spray logic circuit following a simulated automatic initiation test of the B loop of core spray.

Equipment responses to the actuation signals were as per design.

PSE&G is evaluating the exact cause of the problem with the-tester.

The use of this test device has been restricted.

The resident inspectors will follow up on PSE&G evaluations and corrective

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actions.

C.

On February 22 with the reactor ir, a cold shutdown. condition, an inadvertent actuation of the Redundant Reactivity Control System (RRCS) occurred due to,the failure to reset an earlier RRCS initiation

- signal on one channel prior to initiating a design change on a second RRCS channel. The spurious actuation resulted in an alternate rod insertion (ARI) actuation and a recirculation pump trip (RPT) signal.

No control' rod motion resulted because all control rods were already inserted, and both recirculation pumps were out of service. One instrumentation channel had previously been taken out of service, but the controlling procedure did not specify resetting the R..CS logic following the instrumentation's return to service. When the second channel of instrumentation was removed from service for work on c

design change, the RRCS actuation resulted. To prevent recurrence, i

the procedure is being revised to specify resetting both channels of

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RRCS logic both after return to service and prior to removing a channel from service. The inspector concluded that this corrective

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action was acceptable and appropriate.

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D.

The inspector walked down numerous areas of the plant normally '

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inaccessible, including the drywell, torus, sten tunnel, and cleanup heat exchangers. During a February 27, 1989 ir...,,ection of the torus the inspector noted that the torus was in good condition. The water

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quality was excellent, as the bottom of the torus could be seen

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If through 14 feet of water.

However, the inspector noted that a small diameter underwater pipe (approximately 4 inch) had air bubbling through it.. This appeared to be unusual,'because such liquid return

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lines should not be subject to gas' pressure.

System engineering later.-

identified the line as the torus water cleanup return line and stated that'the bubbling would be evaluated and repaired during the planned near term system outage. The inspectors will review corrective actions on the bubbling following the outage. '

E.

The inspector walked down the plant following the restart from the outage, including a drywell entry at 10% reactor power with quality-control and radiation protection personnel. Generally, plant conditions were good.

The inspector found-a steam leak of the Reactor Core Isolation Cooling (RCIC) steam supply isolation valve (F008) in the RCIC pipe chase room which had not been identified. Maintenance and radiological control corrective actions were initiated. Operations Department management stated that every accessible area of the plant is inspected by equipment operators at least weekly and that this steam leak would have been found shortly. The inspector concluded that no corrective actions were appropriate at this time.

F.

The inspector reviewed and witnessed implementation of portions of the semiannual Class 1 fire. door inspection and operability test (M10-SHT-027). The test was comprehensive and performed by knowledge-

. able fire protection personnel.

It appeared to the~ inspector that the operability of a high proportion of fire doors had deteriorated to an unsatisfactory condition since the previous semiannual inspection.

On several occasions.in the past the inspector had identified aeficient fire doors to fire protection personnel (doors which failed to shut and latch due to ventilation problems (differential pressure) or excessive wear. The inspector will review the results of the semi-annual Class 1 fire door inspection when complete.

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EMERGENCY PREPAREDNESS (71707)

During this inspection period no emergency drills were conducted, no events within emergency classification occurred, and there were no noteworthy findings in this area, j

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SECURITY (71707)

PSE&G's compliance with the security program was verified on a periodic basis, including adequacy of staffing, entry control, alarm stations, and

physical boundaries.

There were no noteworthy findings in this area.

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ENGINEERING / TECHNICAL SUPPORT (37828)

(0 pen)Bulletin 85-03 (85-00-03); Supplement 1 to Bulletin 85-03, Motor-Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings, requests valve switch setting data be pruvided for all

safety-related valves in the identified systems.

PSE&G 1etter NLP-N88110 dated July 27, 1988 responded to this request and stated that switch setting data for only one additional valve (RCIC isolation valve bypass) was needed; the data was attached. NRC review of this response concluded that the response met the requirements (action item e.) of the supplement and was acceptable.

Inspections of the program to evaluate and' control the switch settings will be addressed in future inspection reports.

This bulletin remains open.

9.

SAFETY ASSESSMENT / QUALITY VERIFICATION (40500)

A.

During this inspection period, PSE&G identified a pair of electrical jumpers, which had been installed in pump control circuits for over ten months without anyone's knowledge.

Similar uncontrolled modifi-cations of the plant have previously been identified by PSE&G and were cited by the NRC as violations in NRC Inspection Reports 50-354/87-23 and 88-22.

However, the corrective actions for the second violation took place after the incident currently being cited occurred. The potentially serious consequences of uncontrolled modifications of the plant necessitate increased management attention

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to this area.

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The inspectors noted that numerous electrical jumpers and lifted leads are used each day during surveillance testing and that their control in test procedures has been generally good and without problem. The problems have occurred in special situations associated with operating systems, e.g., undergoing modifications or maintenance.

PSE&G should ensure that current administrative controls of such temporary modifi-cations are adequate to prevent further problems.

B.

The inspector noted that PSE&G exhibited excellent problem identifi-cation, communication to plant managemer+, and initiation of corrective action regarding the orientation of containment isolation valves, I

described in Section 4.3.A.

While it was concluded that an expeditious, short term fix was not necessary, PSE&G's recognition of the problem and the immediate initiation of evaluations of such fixes were commendable.

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I 10.

LICENSEE. EVENT REPORT (LER) AND OPEN ITEM FOLLOWUP. (92700)L

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A.

PSE&G' submitted the following event reports and periodic _ reports,'

.which'were reviewed for accuracy and timely submission;

.i Monthly Oper ting Report for January,1989 LER 88-33 Automatic Isolation of the High Pressure Coolant I

Injection System due to Procedure.Non-Compliance (discussed below).

i-LER 88-36 Nuclear Steam Supply. Shutoff System Isolation Signal LI While Performing Surveillance. Test Due to Deficiency

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-in Procedure; discussed in Section 4.3.A of Inspection

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Report 50-354/88-29.

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LER 89-01

. Reactor Water Cleanup (RWCU) System ' Isolation During-l Warmup of B RWCU Pump,.

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'LER.89-02'

Control Room Emergency Filtration (CREF) System Initiation During Surveillance Testing due to Voltage i

Transient in the Logic Circuit.

I LER 88-33 describes an isolation of the High Pressure Coolant'. Injection l

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(HPCI). system due to personnel error during performance of a steam i

leak detection system surveillance test. The technician performing y

the surveillance test did not follow the procedure. The isolation j

occurred at the fourth step in the procedure when terminal leads were lifted in preparation for inserting a dummy signal into the'instrumen-tation.

Prior to this step, the procedure required that an auto-isolation bypass switch be positioned to bypass to prevent an inadvertent isolation. The technician failed to perform this step, i

and when the leads were lifted, the HPCI primary containment outboard

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steam supply valve shut. Within three minutes the isolation was i

reset and HPCI was restored to a normal standby lineup.

This-l'censee-l identified item is not being cited based on meeting the criteria of

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s 10 CFR 2, Appendix C (354/89-02-03).

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B.

The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purposes.

Open 85-00-03 Section 8.A

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11.

EXIT INTERVIEW (30703)

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The inspectors met with Mr. J. Hagan and other PSE&G personnel

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summarize the scope and findings of their inspection activities.

Based on Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.

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