ML20137W781

Insp Rept 50-354/97-01 on 970202-0317.Violations Noted.Major Areas Inspected:Licensee Operations,Engineering,Maint, & Plant Support

ML20137W781
Person / Time
Site:	Hope Creek
Issue date:	04/14/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20137W767	List: ML20137W761 ML20137W770 ML20137W776 ML20137W781
References
50-354-97-01, 50-354-97-1, NUDOCS 9704180209
Download: ML20137W781 (30)

See also: IR 05000354/1997001

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l U. S. NUCLEAR REGULATORY COMMISSION

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j REGION I

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i Docket No: 50-354

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License Nos: NPF-57 I

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{ Report No. 50-354/97-01 l

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Licensee

Public Service Electric and Gas Company

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Facility: Hope Creek Nuclear Generating Station  ;

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j Location: P.O. Box 236

l Hancocks Bridge, New Jersey 08038

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l Dates: February 2,1997 - March 17,1997

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j Inspectors: R. J. Summers, Senior Resident inspector

S. A. Morris, Resident inspector

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Approved by: James C. Linville, Chief, Projects Branch 3

Division of Reactor Projects

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9704180209 970414

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EXECUTIVE SUMMARY

Hope Creek Generating Station

NRC Inspection Report 50-354/97-01

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a 6-week period of resident inspection.

One special inspection activity, a Maintenance Rule team inspection, occurred during this

period; however, the results of that inspection will be documented in NRC Inspection

Report No. 50-354/97-80.

Ooerations -

As a result of the lack of explicit procedural guidance, some operators were confused

regarding the main steam line isolation actuation setpoints for the high radiation safety

feature per the requirements of technical specification 3.3.2 during planned hydrogen

water chemistry injection (HWCI) system flow reductions. (Section 01.2)

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Operators were found to be effectively controlling standby safety auxiliaries cooling system

(SACS) loop temperature; however, operational guidance was not thorough. Additionally, i

the UFSAR did not accurately reflect the current design basis and operating condition  !

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which permits continuous SACS flow to the residual heat removal heat exchangers,

however, the licensee had previously recognized this problem and had initiated appropriate

changes to the UFSAR. (Section 01.3)

Operator response to two plant events was good, in that the necessary immediate actions l

were taken; the events were properly classified in accordance with the licensee's Event

Classification Guide (Emergency Plan); and, NRC reporting requirements were met.

(Section 01.4)

The inspectors concluded that operator performance improvements had occurred during

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this period. (Section 02.1)

The inspectors concluded that the licensee's QA/NSR report on an event involving an

inadvertent half scram was accurate, comprehensive and complete. This report was

viewed as an indicator of good performance in self-assessment activities. Further, station i

personnel performance as described in the report during this event indicated weaknesses in

the use of the corrective actions program, due to personnel not documenting Action

. Requests in a timely manner and in proper log keeping by plant operators regarding plant

conditions. These concerns were considered examples of a non-cited violation. (Section

07.1)

Based on a review of selected records and reports, the inspectors concluded that the

licensee's self assessment process and corrective action program were being appropriately

used and provided valuable performance assessment information to station management.

(Section 07.2)

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Maintenance

The licensee adequately planned and controlled the observed maintenance and surveillance  !

activities. The work was conducted in a professional manner and timely completed to

en ure that equipment restoration to service was within the technical specification

requirements for all observed activities. (Section M1.1)

The licensee's analysis and corrective actions for a human error event leading to a primary

containment isolation system actuation were appropriate. (Section M2.1)

The licensee management actions to reduce the backlog of corrective maintenance work

were evident. While too early to conclude that the management of the work process had

been improved significantly, the trend information from the licensee performance indicators

was positive. (Section M2.2)

The licensee plans and corrective actions were found reasonable for the identified concerns

with degraded Agastat GP Series and Struthers-Dunn relays. However, the NRC was

concerned that: (1) the material condition of the plant was adversely affected by these

degraded conditions; (2) the conditions indicated weaknesses in the licensee's planned

maintenance program and industry operating experience program; and, (3) extensive

evaluation and repairs were necessary to resolve these relay problems while the plant was )

on line. (Section M2.3) )

Hope Creek test procedures for safety-related ventilation trains do not implement technical

specification surveillance requirements consistendy. (Section M3.1)

The OA audit of the maintenance program showed that additional improvements were

warranted in the maintenance area. The audit activity was well planned and excellently

performed. The audit findings were well supported by observations and provided i

significant information to management in order to improve the maintenance programs. '

(Section M7)

Enaineerino

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The licensee's implementation of Design Change Package (DCP) No. 4EC-3411 was, in

part, based upon a weak 10 CFR 50.59 evaluation, which indicated a weakness in the

engineering development, review and approval process of 10 CFR 10 CFR 50.59

evaluations to support design changes. The licensee's evaluation failed to identify a

potential unreviewed safety question involving a malfunction of equipment important to

safety (Iow pressure coolant injection system) and need for a technical specification

requirement change in order to implement the rnodification. Further, since this DCP was

implemented over the course of several years with different parties involved in the 10 CFR

50.59 review and approval, it was further concluded that numerous opportunities were

available for the licensee to identify this problem. (Section E1.1)

While a potential unreviewed safety question was identified, the inspector verified that the

residual heat removal (RHR) system cross-tie isolation valves were properly installed,

providing double isolation capability; and, that the valves were being maintained closed

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ensuring the independence of the low pressure coolant injection (LPCI) subsystems.

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(Section E1.1) .

The inspector also concluded that DCP 4EC-3411 documentation was thorough. The

observed portions of the completed field work indicated good installation implementation.

Testing considerations were found appropriate and test completion timely. (Section E1.1) ,

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A repeat failure of the reactor core isolation cooling (RCIC) system turbine exhaust check

valve inservice test highlighted past deficiencies in PSE&G's design change process to l

ensure that modifications implemented to correct failures were designed appropriately. l

Also, this repeat failure indicated a weakness in the corrective action program to ensure

that the failure was corrected. However, the recent effort to identify causal factors  ;

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associated with this event and develop lasting corrective actions was good. (Section E2.1)  ;

Poor implementation of established scaffolding control guidance enabled the installation

and retention of several scaffolds in safety-related areas, including the "A" and "B"

residual heat removal pump rooms and the standby liquid control pump room in the reactor

building of the Hope Creek station without adequately evaluating the impact of these I

structures on the design and licensing basis of the facility. This was considered a violation l

of licensee procedure controls. (Section E2.2) '

Plant Support

PSE&G appropriately tested the EDG room ventilation fire dampers and has established

appropriate controls to ensure this activity is completed on a periodic basis and in

accordance with the programmatic description in the UFSAR. (Section F2.1)

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I TABLE OF CONTENTS i

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1 EX EC UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il

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TA B L E O F C O NT ENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v  !

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1. O pe r a tio n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l

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11. M ai nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

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Ill. Engineering .................................................. 14 .

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I V. Pl a nt S u p port . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 ,

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! V. Ma nagement Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 }

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Report Details

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l Summarv of Plant Status

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Hope Creek began the inspection period at 100 percent power. Full power operations were

l' maintained throughout the inspection period spanning February 2,1997 to March 17,

1997, except for minor power reductions to support maintenance and testing activities.

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4 1. Operations

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01 Conduct of Operations i

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! 01.1 General Comments (71707)

i Using Inspection Procedure 71707, the inspectors conducted frequent reviews of

i ongoing plant operations. In general, the conduct of operations was professional

! and safety-conscious; specific events and noteworthy observations are detailed in

j the sections below.

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j 01.2 Operation of the Hvdroaen Water Chemistry Iniection System

a. Insoection Scope (71707)

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i Following a period of hydrogen water chemistry injection (HWCl) system testing by I

i Hope Creek personnel, the inspectors reviewed operations department procedural  ;

, guidance related to the impact of HWCl system flow rate changes on plant

j operation, primarily to ensure that technical specification compliance was i

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b. Observations and Findinas

On February 19,1997, as part of a planned evolution, operators terminated HWCl

l system injection flow to the reactor vessel for approximately 6% hours. The net

j effect of this action was a reduction in radiation levels detected by the main steam

line radiation monitors (MSLRM). These monitors provide an engineered safety

l feature (ESF) actuation when a radiation threshold equivalent to 3 times normal full

i power background is exceeded (per TS 3.3.2). When HWCl flow is terminated, full

power radiation levels are reduced, and the MSLRM trip setpoint for ESF actuation

becomes non-conservative. The inspectors questioned senior licensed operators

about how TS 3.3.2 action requirements, which mandate that the associated  ;

instrument channels be declared inoperable when tnp setpoints are non- l

conservative, were satisfied since no active action statement entry was made j

during the period of time HWCl flow was secured. The inspectors noted confusion  ;

among some interviewees regarding the appropriate action required during this time  ;

and the basis for such action.

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Based on subsequent research into this issue, the inspectors determined that

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operational guidance existed, but only in an alarm response procedure associated '

with a "HWCl Trouble" overhead annunciator in the control room. When overhead

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annunciator alarms are expected due to planned station activities, associated alarm

response procedures are frequently not consulted. The HWCl alarm response

procedure, HC.OP-AR.ZZ-0003 Attachment B3, requires that operators notify l&C

technicians when HWCl is secured for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in order to have the i

MSLRM setpoints adjusted commensurate with non-HWCl full power background

levels (to meet the intent of TS 3.3.2). The inspectors determined that TS

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Amendment 8 explicitly mandated the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action requirement, but that this

action time was subsequently eliminated in Amendment 23. The operations

department established a TS interpretation following Amendment 23 which retained

the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time requirement, but this interpretation was later canceled in 1995,

leaving little explicit procedural guidance to ensure the intent of TS was maintained i

during planned HWCl system flow reductions. l

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c. Conclusions i

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The inspectors judged that, as a result of the lack of explicit guidance, confusion

still existed among some operators regarding the actions necessary to implement

the requirements of technical specification 3.3.2 during HWCl system flow

reductions.

01.3 Standbv Safety Auxiliaries Coolina System Looo Operation

a. Insoection Scope (71707,37551)

The inspectors reviewed procedural guidance and observed station operators to

evaluate the manner by which the standby safety auxiliaries cooling system (SACS)

loop temperature was controlled. Additionally, the inspectors evaluated the basis

upon which the SACS temperature control band was established.

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b. Observations and Findinas 1

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On February 7,1997, the "C" filtration, recirculation, and ventilation system (FRVS)

recirculation unit failed its technical specification required monthly surveillance test.

The unit tripped off line due to moisture collecting in its differential pressure  :

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instrument sensing lines (which caused abnormal flow indications) due to excessive

condensation buildup in the FRVS ventilation ductwork. PSE&G's preliminary root

cause assessment attributed the excessive condensation to unseasonably low SACS

system temperatures (SACS cools the FRVS unit coolers) which were below the

dew point for the reactor building atmospheric conditions at the time of the test.

The inspectors determined that operations department procedures permith <f SACS

operation to temperatures as low as 32 F. Upon questioning the basis for the SACS

minimum temperature limit, operations staff stated that it was in part based on an

engineering evaluation completed following an earlier station event involving

operation of the SACS system below design temperature limits. Specifically, a

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November 6,1995 discovery that the SACS system was being operated below the

(then) FSAR described minimum temperature of 65 F resulted in a revised

engineering assessment of the impact of low SACS temperatures on the system's

structural integrity (see also Section 4.1 cf NRC Inspection Report 50-354/95-19).

At the conclusion of the report period, PSE&G was conducting an investigation to

determine whether the current operating limit of 32 F was inappropriately based on

an engineering evaluation which did not evaluate the impact of low SACS

temperatures on components and systems cooled by SACS. Pending the results of

this licensee offort, this issue remained unresolved. (URI 50-354/97-01-01)

Because of the FRVS operability implications stemming from the event described

above, station management required plant operators to control temperature in the

SACS loons within a band of 55 to 90 F. Because of low service water system

(which cools SACS) temperatures, the automatic SACS system temperature control

valve (bypass around the SACS heat exchanger) could not bypass enough flow to

keep the minimum SACS temperature above SS F in the standby (loop not

supplying TACS) toop. As a result, operators manually controlled standby SACS

loop temperatures according to the guidance in SACS operating procedure, HC.OP-

SO.EG-0001.

On March 11,1997, the inspectors observed operators conducting a manual SACS

loop temperature control evolution. The operators were thoroughly familiar and

proficient at performing this activity. Upon review of the applicable section of the

governing operating procedure noted above (revision 17, Section 5.14), the ,

inspectors discovered a note that generally described two acceptable methods to I

accomplish manual temperature control. However, only one of the two methods

was explicitly described in the procedure; the inspectors determined that operators

were employing the other non-specifica//y stated method. During subsequent

questioning of the senior operators about this apparent lack of explicit operational

guidance later in the day, the inspectors learned that a previously approved

procedure revision had just been issued to clarify the loop temperature control

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in addition, the inspectors noted that the plant operators maintained SACS flow  !

through the residual heat removal system heat exchanger (RHRHX) associated with I

the standby SACS loop. This activity is also prescribed by the above noted SACS 1

operating procedure and has been the normal practice since initial facility operation.

The inspectors observed that, while this activity had been appropriately analyzed for

technical acceptability, the design basis documentation in the FSAR had not been

updated to reflect this operating practice. Specifically, figure 9.2-4 (piping and

instrumentation drawing M-11-1 sheet 1) lists the valves which permit SACS flow

through the RHRHX (EGHV-2512A/8) as normally closed. However, Hope Creek

personnel were able to demonstrate that, not only was this issue previously self- )

identified, but that a change to the applicable FSAR section to reflect actual j

operating practice was developed tc address this discrepancy and would be

incorporated into the next FSAR revision. The inspectors concluded that this failure

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to update the FSAR in a timely manner constituted a violation of minor significance l

and was a Non-Cited Violation, consistent w% Section IV of the NRC Enforcement l

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c. Conclusions

Operators effectively controlled standby safety auxiliaries cooling system loop  !

temperature, but the operational guidance that established the methodology l

l employed did not explicitly describe the activity. Even though not adequately

described in procedures, operators were able to use their knowledge of the system

! to perform this control acceptably. (Subsequent to NRC observation the licensee i

improved the procedure guidance to document the means employed by the

, operators.) Additionally, the FSAR did not accurately reflect the current design 1

basis and operating condition which permitted continuous SACS flow to the residual l

, heat removal heat exchangers, t

01.4 Operator Resoonse to Events

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Two non-emergency event notifications were made during this report period. The

first event involved the reactor core isolation cooling (RCIC) system being declared

inoperable due to a failure of the RCIC turbine exhaust testable check valve on

February 4,1997. Additional information on this event and the licensee's

corrective actions are found in Section E2.1 of this report. The second event

involved an inadvertent actuation of the containment isolation system due to a

failure of an associated radiation monitoring system during a troubleshooting activity

, on February 7,1997. Additional information on this event and the licensee's  ;

corrective actions are found in Section M2.1 of this report. The inspectors

concluded that operator response to the events was good, in that the necessary

immediate actions were taken; the events were properly classified in accordance

with the licensee's Event Classification Guide (Emergency Plan); and, NRC reporting

requirements were met.

I O2 Operational Status of Facilities and Equipment

O2.1 General Observations -

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Throughout the period, the inspectore noted several examples of generally improved

operations department performance, particularly in the areas of operator log

keeping, control of maintenance and testing activities, and control board

manipulations. Pre-job briefs continued to be frequent and thorough, and the

willingness to halt in-progress work activities when unexpected conditions occurred

was evident. This was especially notable during recent efforts to troubleshoot and

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repair a non-Class 1E Bailey Logic Control power supply which had the potential to

induce a significant plant transient. The inspectors witnessed good contingency

planning for the potential impact of a loss of an operating SACS pump during a

maintenance activity involving SACS to TACS isolation valves. In addition to the

aforementioned contingency planning improvements, the inspectors observed use of

a newly instituted " peer check" process for routine board manipulations. The

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inspectors noted that this practice reinforced control room operator's use of the

stop, think, act, review (STAR) principle. Also, recent operations department

emphasis on reducing the number in response to outstanding control room

deficiencies has resulted in improved performance of alarms and fewer distractions

to operators. The inspectors concluded that performance improvements had

occurred during this period.

07 Quality Assurance in Operations

07.1 Quality Assurance / Nuclear Safety Review (QA/NSR) Surveillance Report Review

a. Insoection Scone (71707)

The inspectors reviewed a QA/NSR surveillance report, dated March 4,1997,

conducted on an event involving an inadvertent half-scram event on January 29, i

1997. In addition, the corrective action program (CAP) Performance improvement

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Request Nos. 00970204271 and 00970225108 were reviewed to assess I

completion of corrective actions for CAP performance deficiencies identified in this i

report and related reports.

b. Observations and Findinas I

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The QA/NSR surveillance report was conducted to evaluate Hope Creek and

QA/NSR management response to the inadvertent half-scram event that occurred

during the performance of a routine surveillance activity (channel calibration) on the

"G" intermediate range monitor (IRM) on January 29,1997. The inspector found

the report to be of very good quality, thoroughly describing: the sequence of

events; analysis of expected actions for the conditions observed during the

. sequence; and conclusions, including proposed corrective actions for activities that

failed to fully meet expectations. The report identified that the cause of the event

was due to a failure of a hold down device used to depress and hold the "G" IRM

INOP INHIBIT switch during channel calibration.

While the IRMs are not required for power operations, routine calibrations are

performed in order to maintain operability of the equipment in case of the need to

shutdown tne reactor, when the IRMs are necessary. The calibration test normally

initiates several half scram signals. Control of other activities at the time reduces

the risk of the testing causing plant transients. However, on this occasion, the hold

down device slipped off the INOP INHIBIT switch and resulted in an unexpected half

scram. The report went on to describe several corrective action program

performance failures and record keeping deficiencies by the personnel involved in

the even'. and initiated corrective actions for those problems. The nature of the

performance problems were that the individuals did not document the unexpected

half screm in an Action Request in a timely manner, nor were control room log

entries of sufficient detail to describe the events occurrence. While the cause of )

> the event was a failure of an apparatus used to support testing, failure of the

personnel to properly use the corrective actions program to document and resolve 3

the condition adverse to quality was considered a violation of station procedures.  !

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i in a related event not documented in the referenced QA/NSR report, on February

. 22,1997, the licensee identified that an equipment operator accidentally hit a i

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control that caused a loss of the sample pump for the South Plant Vent on February

16, while taking readings for the associated system per the technical specifications

(TS). The equipment operator immediately informed the control room and the

sample pump was restored within several minutes; however, the event caused an

unexpected entry into a TS limiting condition for operation. Further, operators failed

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to properly document this condition in accordance with the corrective actions

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program for six days. The CAP expectations are that conditions adverse to quality ,

should be documented and approved within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the occurrence. As a 1

) result, the inspector reviewed related information describing performance

deficiencies in the use of the corrective actions program and in log keeping.

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j The license:h's cocective actions for the above two problems and similar events that

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occurred during the inspection period were considered appropriate. Individuals were l

cowseled and both remedial and continuing training established in the proper use of

the corrective actions program, as well as proper log keeping. Also, these events

were alllicensee identified. While the events were related in that the plant

personnel failed to use the corrective actions program to document conditions  ;

adverse to quality appropriately, the timing of the events were such that the

corrective actions for the first event were not completed prior to the occurrence of

the later events. As such, these examples of a licensee identified and corrected

violation are being treated as a Non-Cited Violation, consistent with Section Vll.B.1

of the NRC Enforcement Policv.

c. Conclusions

The inspector concluded that the licensee's QA/NSR report was accurate,

comprehensive and complete. The analysis of the event considered not only the

apparent root cause for the unexpected half scram condition, but included

performance assessment for the personnel involved in the test, as well as for line

management and independent review staff that had opportunities to identify

weaknesses in the use of the corrective actions program that were discovered after

the event. This report was viewed as a indicator of good performance in self-

assessment activities. Further, station personnel performance during these events

indicated weaknesses in the use of the corrective actions program and in proper log

keeping; although, self assessment activities and corrective actions for the

performance related aspects were considered good.

07.2 QA/NSR/Licensina Monthlv Reoort and Other Self-Assessment Activities

The inspectors reviewed the QA/NSR/ Licensing Monthly Report for January 1997,

NOS-97-008, dated February 21,1997. The report provided the combined results

of independent assessments for both the Salem and Hope Creek generating i

stations. The report provided findings based on the following performance j

standards: (i) items requiring management attention or needs improvement; (ii) items l

which meet current standards but have shown some deviation in the level of l

performance; and, (iii) items indicative of excellence. The inspectors noted that the j

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report contained no items indicative of excellent performance associated with Hope

Creek and described a number of areas requiring additional management attention,

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including: human performance issues in operations; failure to adhere to the

corrective action program standards resulting in non-conservative classification of

conditions adverse to quality (CAQs); inappropriate scheduling of work activities

resulting from multiple barrier failures; a higher than desired corrective maintenance

3 backlog and trend; instances of security related failures or human performance

errors and inappropriate classification of the significance of these conditions. The

inspectors noted that the monthly report provided valuable performance assessment

analysis. The conclusions and recommendations were well supported by the

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observations described in the report. Further, the identified areas warranting

additional management attention were found to be consistent with findings made by

the NRC.

The inspectors reviewed the Fourth Quarter 1996 Trending Report, NOP 97-0015,

dated March 5,1997. The report provided a trending analysis of significance level l

1 and 2 condition resolution evaluations initiated in the fourth quarter of 1996. The

purpose of the trend report was to aid station management in focusing efforts to

prevent significant human errors. The trend report indicated that the nuclear

procedure control process showed improvement at Hope Creek. Areas showing an

adverse trend included: the 10 CFR 50.59 review process and site i

protection / security performance. The inspectors considered that the report  :

contained valuable trending information regarding human performance concerns and -l

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cstablished the drivers for the errors, such as whether the errors were caused by

skill based, knowledge based, or rule based errors. This type of analysis provided

excellent insight into the root cause(s) of human errors and could assist in

development of preventive actions. Further, the identified areas with an adverse

trend were found to be consistent with findings made by the NRC.

The inspectors reviewed selected significance level 1 CAQs that were initiated

during the inspection period, including: Performance Improvement Request Nos.

00970128173, Ineffective implernentation of the Work Management Process;

00970204307, Failed IST Testing of Testable Check Valves; 00970206295,

Untimely Evaluations of Out of Calibration Measurement and Test Equipment; and

00970207331, "B" Channel Primary Containment Isolation System Actuation. The

inspector found that all of the selected reports were easily retrievable from the

licensee's CAP data base. All of the reports accurately described the CAQs that led

to the corrective action evaluations. The inspector reviewed the licensee's

administrative procedures and verified that the CAQs were appropriately classified

and that timely resolution of the conditions were either completed or planned.

Based on a sampling review of the identified corrective actions, the inspectors

found for these more significant conditions that the licensee was meeting the

expectations of the CAP.

Based on a review of select records and reports, the inspectors concluded that the

licensee's self-assessment process and corrective action program were being

appropriately used and provided valuable performance assessment information to

station management.

8

08 Miscellaneous Operations issues

J

08.1 (Closed) URI 50-354/94-22-02: This unresolved item was the subject of an

investigation that resulted in enforcement actions described in NRC Inspection

Report 50-354/95-16. The unresolved item is administratively closed and future

follow up inspection activities will reference the noted violations. I

II. Maintenance

M1 Conduct of Maintenance

l

M1.1 General Comments

a. Inspection Scope (62707 and 61726) l

The inspectors observed all or portions of the following work activities:

-

Bailey Non-1E Power Supply Repair

-

"A" and "B" RHR system outages

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RCIC system outage

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"D" emergency diesel generator (EDG) system outage {

The inspectors observed all or portions of the following surveillance procedure (s):< {

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Filtration, Recirculation, and Ventilation system testing

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"D" EDG monthly operability surveillance testing ,

b. Observations and Findinos

in general, the inspectors noted that the work activities were appropriately

accomplished; that the work packages were of good quality; that the technicians

adhered to the procedures; and that the work areas were restored to an excellent

material condition. As previously stated in Section 01.2 of this report, the level of

contingency planning and work coordination with the operating staff was also noted

to be good. Except as noted below in Section M3.1, surveillance testing activities

were also found to be well conducted and satisfied the requirements of the

associated technical specifications. ,

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c. Conclusions  !

l

The inspectors concluded that the licensee adequately planned and controlled the  ;

observed maintenance and surveillance activities. The work was conducted in a i

professional manner and timely completed to ensure that equipment restoration to

service was within the technical specification requirements for all observed

activities.  !

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M2 Maintenance Support of Facilities and Equipment i

M2.1 "B" Primarv Containment isolation Actuation

The inspector reviewed the licensee's response to an event involving personnel error i

during a troubleshooting maintenance activity that led to an automatic actuation of

the "B" Primary Containment isolation System on February 7,1997. An

annunciator had failed to clear as expected during the performance of a radiation

monitoring system channel calibration. As a result, technicians placed the affected

channel, "A", of the Reactor Building Exhaust Radiation Monitor into a tripped

condition. Later that same day after shift turnover, technicians were asked to verify

the status of the tripped channel. While taking readings to verify the channel status ,

with a Digital Multimeter, the technician erroneously made contact with the wrong

terminal point, causing the "B" channel of the system to trip. With two of the three

channels tripped, a "B" Division PCIS actuated as designed. Operators verified that {

all equipment responded as expected for the actuation signal; verified the cause of

the event and reset the actuation logic; and reported the event to the NRC in

accordance with emergency plan procedures. The actuation had little affect on the

plant; however, due to expected valve isolations, the drywell equipment floor drain

sump (RCS leakage monitoring system) was inoperable for a short time. The

licensee determined that the cause of the original annunciator problem was a failed

optical isolator in the circuit. The cause of the actuation signal was personnel error

during the troubleshooting activity for the initial problem. The licensee's corrective ,

actions included: replacing the failed optical isolator card; disciplinary actions for

individual personnel performance deficiencies; planned training on the root causes of

this event for station l&C technicians; planned reviews of prior similar events to

'

verify implementation and status of prior corrective actions; and, planned

preparation of guidance for verifying relay contact position. The inspector

concluded that the licensee's analysis and corrective actions were appropriate.

M2.2 Corrective Maintenance Backloas

During prior assessments of Hope Creek performance, NRC has expressed concern  ;

with the high backlog of corrective maintenance. During this period the inspectors -

observed weekly management discussions to improve this situation and have

monitored the licensee's progress. During this period, station management -

essentially completed an initial validation of the corrective maintenance backlog.

This resulted in reducing the number of backlog items due to removal of repetitive ,

work requests for the same condition and removal of items due to work already j

being complete. In addition, the work week schedules have been adjusted to place i

a high priority on backlogged corrective maintenance items. As a result of these

efforts, the backlog has begun to be reduced. The latest performance indicators for

this issue show that the backlog is down to about 850 items (by end of February) l

from about 1200 items by the end of 1996. The inspector concluded that the

licensee management has initiated actions to reduce the backlog of work. While it

is too early to conclude that the management of the work process has been

improved significantly, the trend information from the licensee performance

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indicators is positive. In addition, the inspector has observed improved

management attention and focus in this area.

M2.3 Aaastat and Struthers-Dunn Relav Concerns

The inspectors reviewed the licensee plans and actions in response to two condition

reports during the inspection period for possible age related degradation of normally

energized, Agastat "GP Style" relays, and for normally energized, Struthers-Dunn

relays that had wrong manufacturing rr.aterials. The Performance Improvement

Request Nos, for these two concerns were 00970218207 and 00970306444,

respectively. The licensee developed action plans for each issue. The inspectors

! reviewed the plans and observed periodic management briefings on the results

l achieved to date on resolution of the concerns. At the close of the inspection

period, the licensee had developed bases for operability determinations for any

degraded conditions identified in the plant for safety related application of the two

types of relays. Activities were nearly complete in verifying all the applications for

the relays in the plant systems and plar s were being formed to replace potentially

unqualified or non-conforming relays.  :

in the case of the Agastat GP Style relays, no recent failures have been identified;

however, the qualified service life for a number of the installed relays ex;-ires on -

April 15,1997. Based on preliminary estimates, about 60 of these relays, used in

safety related applications, will need to be replaced. Engineering support work was

stillin progress to identify the scope of repair for non-safety related relays. ,

in the case of the Struthers-Dunn relays (Series 219NE), several recent failures of

this type relay had been identified. These relays are used extensively in safety

related applications such as: the Remote Shutdown Panel, the Bailey solid state

logic cabinets, and HVAC panels. The licensee found that a number of the installed

relays had degraded with visible evidence of heat damage to the magnetic vinyl

plastic bearing pad materialin the relay. The vendor stated that the visible

degradation was not proof positive that the relay was inoperable; but rather, told  ;

the licensee that the relay would begin to " buzz" noticeably prior to failure. Further,  ;

the licensee determined that the manufacturer had replaced the bearing pad material

with a silicon rubber based material that was not susceptible to this heat related

f ailure mechanism in 1983. During verification walkdowns of the installed relays at

Hope Creek, engineers determined that some of the relays manufactured after 1983

still used the vinyl plastic bearing pad. Based on early estimates, the licensee plans

to repiace about 60 of the Struthers-Dunn relays due to visible signs of degradation.

In addition, based on the apparent manufacturing defects identified during the

walkdowns of the installed relays, the licensee is evaluating the need to issue a 10

CFR Part 21 report. j

The inspectors concluded that the licensee plans and corrective actions were '

reasonable for the identified concerns. However, the inspectors were concerned

that: (1) the material condition of the plant was adversely affected by these

l

degraded conditions; (2) the conditions indicated weaknesses in the licensee's

planned maintenance program and industry operating experience program; and

. _

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extensive evaluation and repairs were necessary to resolve these relay problems

j while the plant was on line and relying on the equipment. This matter is unresolved I

pending further inspection to determine the causes of the problems. (URI 50-

354/97-01-02)

M3 Maintenance Procedures and Documentation

M3.1 Surveillance Testina of Safetv-Related Ventilation Systems

a. Insoection Scoce (62707. 37551) '

a

The inspectors reviewed the adequacy of Hope Creek's TS surveillance testing of

safety-related vent 0ation trains, including the FRVS and the control room effluent

filtration system (CREF).

b. Observations and Findinas

The Hope Creek TS surveillance requirement for FRVS Recirculation, TS 4.6.5.3.2,

states in part that "each of the six FRVS recirculation units shall be demonstrated

operable...by... verifying that the subsystem operates for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the

heaters ONin order to reduce the buildup of moisture on the carbon absorbers and

HEPA filters." Similar surveillances are required for the two FRVS ventilation trains  ;

and the two CREF trains (per TS 4.6.5.3.1.b and 4.7.2.b respectivcly). The bases

for the noted T.S. consistently state that " continuous operation of the system with

the heaters and humidity control instruments OPERABl.E for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />...is sufficient

to reduce the buildup of moisture on the absorbers and HEPA filters."

Regulatory Guide 1.52 revision 2 (March 1978), to which the licensee is committed

per the Hope Creek FSAR, section C.4.d, states "each ESF (engineered safety

feature) atmosphere cleanup train should be operated at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per month,

with the heaters ON (if so equipped), in order to reduce the buildup of moisture on

the absorbers and HEPA filters.

The inspectors determined that the Hope Creek procedures which implement the l

noted TS are not consistent with respect to atmosphere cleanup system heater 1

operation. Specifically, the FRVS testing procedures require only that the heaters

be energized at the beginning of the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> run by reducing the associated

humidity controller to 0%, then restoring the controller set point to 55% for the ,

remainder of the test. This method allows the heaters to cycle as necessary to  ;

maintain the established humidity level. However, the CREF surveillance tests j

ensure full literal compliance with the TS by maintaining the heaters energized

(humidity controller set to zero) for the duration of the test.

During inspector questioning of this apparent inconsistency, Hope Creek engineering

and licensing staff stated that the method employed for FRVS testing meets the

intent of the TS by ensuring that the heaters are only OPERABLE (i.e. not "ON"), as

stated in the associated bases. The inspectors learned that Hope Creek

management was developing a TS amendment to revise the noted requirement to

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match the words in the bases. However, no similar amendment was planned for

CREF. Pending a technical evaluation of the adequacy of the Hope Creek FRVS i

surveillance test methodology by the NRC's Nuclear Reactor Regulation l

organization, this issue will remain unresolved. (URI 50-354/97-01-03) i

c. Conclusions  ;

I

Hope Creek test procedures for safety-related ventilation trains do not implement i

technical specification surveillance requirements consistently, indicating either a j

failure to establish an appropriate test procedure or a failure to identify a

discrepancy in the station's licensing basis.

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M7 Quality Assurance in Maintenance

As stated in Section 07.2 of this report, the inspectors reviewed two significant

level 1 CAQs during this period. The first was a result of line management j

concerns with implementation problems in the work scheduling process (PIR No. l

970128173). A review team was initiated to review all prior work week schedule

problems and routine critiques to determine if further actions were warranted. The

team identified seven issues affecting the overall effectiveness of the work

management process. Among the more significant were: (1) need for improved

management oversight for the process; (2) need for common priorities; (3) need for

more effective allocation of resources to support the planned work; (4) need for

more effective use of work schedule critique insights and self-assessment; and, (5)

need to validate and manage maintenance backlogs. The inspector noted that many

of the planned corrective actions to improve the work management process were

scheduled, but not complete at the close of the inspection. The planned actions j

appeared to be appropriate considering the needs determined by the review team. '

The second significant CAQ was a result of a QA audit of maintenance activities.

During the audit, significant deficiencies (PIR No. 970206295) were identified in the

control and calibration of Measurement and Test Equipment (M&TE). The specific

concerns involved untimely evaluation reports for M&TE found out-of-calibration and

lack of a formal training program for personnel who perform M&TE calibrations. A

number of corrective actions were immediately implemented, including a work stand

down for the associated maintenance shops to explain the significance of the

concerns. Additional findings of lesser significance than that involving out-of- l

calibration M&TE were made during the maintenance audit. The inspector

concluded that while the audit showed that additional improvements were

warranted in the maintenance area, the audit activity was well planned and

excellently performed. The audit findings were well supported by observations and

provided significant information to management in order to improve the maintenance

programs.

.

13

M8 Miscellaneous Maintenance issues

.

M8.1 4160 Volt Switchaear Maintenance Error

i

On January 28,1997, the licensee identified to the NRC that four, Class 1E 4160

volt switchgear, Model No. 5HK-350-1200A, manufactured by Asea Brown Boveri,

had been improperly assembled by the vendor during refurbishment conducted in

early 1996. Of sixteen breakers refurbished by the vendor, four were found to be

mis-assembled. The nature of the problem was that bushings used to align the

charging spring attachment points to the breaker assembly had beeri reversed,

resulting in the springs being mis-a!igned. On one of the breakers, the output

breaker for the "C" EDG, the mis-alignment was causing some visually detectable

rubbing on the breaker assembly internals. Based on licensee and vendor analysis,

the visible wear marks were not considered to be significant enough to result in the

inoperability of the breaker. However, while repairs and testing were being

conducted, the "C" EDG output breaker was replaced with a spare breaker known

to be unaffected by this error. The licensee verified that the remaining three ,

breakers had not been cycled opened and closed excessively (two of the breakers I

were used in vital bus substation feeder breakers that had not been cycled since ,

startup in March 1996; and the third was the "A" EDG output breaker that had l

many fewer operating cycles than the "C" EDG output breaker). The licensee  ;

concluded with vendor support, that the remaining three breakers could be used I

satisfactorily in their current applications without concern. The licensee did initiate j

<

work orders, however, to replace these three breakers at the earliest outage of l

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sufficient duration, or no later than Refueling Outage 7. Subsequently, the NRC i

contacted the vendor on February 6,1997. Based on information known at that- l

time, the vendor stated that the mis-alignment would not affect the operation of the I

i breakers; however, replacement within three years was recommended. Further, the .d

vendor stated that if evidence of the springs rubbing against the breaker frame I

occurred, then the breaker should be repaired as soon as possible. Since the I

licensee had replaced the only breaker showing evidence of rubbing or unusual wear  ;

and since the licensee planned to repair the remaining breakers within the three  !

,

years recommended, the inspector concluded that this concern was appropriately )

resolved by the licensee.

M8.2 (Closed) LER 50-354/97-04: "B" division primary containment isolation due to

personnel error during troubleshooting. This event is discussed in Section M2.1 of

this report. No new issues were revealed by this LER.

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111. Enaineerina

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E1 Conduct of Engineering

E1.1 Desian and Installation of Plant Modifications - Shutdown Coolina Cross-tie

a. Inspection Scooe (37551)

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The inspectors reviewed selected portions of the completed design change

packages that installed the cross-tie capability to the RHR system during Refueling

Outages 5 and 6 to determine if adequate controls were implemented to maintain

the original design basis of the affected systems and to ascertain if the plant

modification packages contained clear and accurate installation and test

instructions.

I

The inspectors reviewed selected portions of Design Change Package (DCP) No.

4EC-3411 to ascertain that the design, installation and testing of the RHR cross-tie ]

subsystems were accomplished safely and introduced no unreviewed safety 1

questions.

b. Observations and Findinas

l

DCP 4EC-3411 involved the modification of the RHR system to install a discharge l

cross-tie between the "C" header and the "A" RHR heat exchanger, and also

'

between the "D" header and the "B" RHR heat exchanger. This modification

involved

the installation of two 18-inch cross-tie headers and associated vents and

drains; installation of structural supports for the new cross-tie piping and

modification of original piping and structural supports in the RHR rooms to climinate 4

interference with the new equipment; core bore new wall penetrations to facilitate I

the installation of the new piping; changes to the pump start control interlocks to

add a new key-lock bypass switch for the "C" and "D" RHR pumps to permit pump l

start with their respective torus suction valves closed; and, installation of four (two l

per cross-tie) new 18-inch,300 psi, Anchor Darling cross-tie gate isolation valves, '

two of which were to have Limitorque motor-operators.

1

The installation of this modification was completed over several years commencing

with work on the "A" and "C" cross-tie during Refueling Outage 5 in March 1994,

and completing with "B" and "D" cross tie during Refueling Outage 6 in March

1996.

In the area of design control, the inspector observed that the modification packages

provided adequate post-modification testing instructions. The testing requirements

were reviewed and found consistent with the appropriate requirements. Also noted

was that some testing had not been completed for the motor operators on the new

cross tie isolation valves. However, that part of the design change, providing

electrical power to the motor operators, had not yet been field completed.

Therefore, deferring the motor operator testing was not a problem.

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The inspector noted, that considering the complexity of the DCP, very few field

- changes were required for this modification, indicating that the change package was l

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of high quality. A sample of SORC meeting minutes were reviewed to ensure that

the DCP and the associated 10 CFR 50.59 safety evaluation were reviewed and l

approved by SORC prior to implementation. During a review of one of the

associated SORC meeting minutes, dated September 27,1995, the inspector noted

that SORC had requested the PRA group perform an analysis of the design change

due to the creation of new high stress locations for the associated piping. PRA

provided an estimate that the introduction of the new high stress locations for the

moderate energy RHR piping resuked in at worst, an insignificant increase in the

average Core Damage Frequency. SORC then approved the 10 CFR 50.59 -

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evaluation based on this clarification. l

The inspector noted that the design change review and approval and the necessary

procurement of components was completed in a timely manner to support the l

modification implementation. Further, the modification package provided clear

installation instructions. Also, the inspector reviewed the UFSAR changes that

were made to incorporate the new design, and found that the licensee had properly

revised the UFSAR. The inspector walked down accessible portions of this

modification and found that the as-built configuration agreed with the design

drawings and that the new flow path valves were allin their required positions

i

(closed) per the licensee's system alignment procedures for the current operating

condition (power operations).

The inspector reviewed the associated 10 CFR 50.59 evaluations for the

modification and found that they were written clearly and except as described

below, provided sufficient bases for the acceptance of the proposed modification.

One concern that the inspector noted was that the safety evaluation did not

consider an erroneous valve lineup that would lead to two of the RHR subsystems

(Low Pressure Coolant Injection or LPCI subsystems) being cross-tied during power

operations as a credible failure. It appeared to the inspector that the licensee

accepted this design because the modification was single-failure proof dncluded ,

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dual isolation valves) and had a;nropriate administrative controls to ensure proper

valve lineup, that the original damgn and licensing basis (as stated in Section 6.3 of

the UFSAR) of having four separate LPCI subsystems was maintained.

The inspector considered that the UFSAR description of LPCI stated:

"LPCIis an operating mode of the RHR system. Four pumps deliver water

from the suppression chamber to four separate reactor vessel nozzles and ,

inject directly into the core shroud region. . . ."

Also, Section 5.4.7.1 of the UFSAR describes the design bases of the RHR System

as:

L

"The RHR System consistit of four independent loops A, B, C and D as

shown in Figure 5.4-13. Each loop contains a motor driven pump, piping,

valves, instrumentation, and controls. Each loop takes suction from the

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suppression pool and is capable of discharging water to the reactor vessel

via separate LPCI nozzles, or back to the suppression pool via a full flow test

line."

Further clarification of this original licensing basis is found in Section 6.3.1 of

NUREG 1048, Safety Evaluation Report related to the operation of the Hope Creek

Generating Station, which states:

"The LPCI system is provided to replace reactor vessel water inventory after

large pipe breaks. The system is an operating mode of the residual heat

removal system, it consists of four independent loops. Each loop has a

motor-driven pump that takes suction from the suppression pool and supplies

Wdter to the reactor vessel at a flow rate of about 10,000 gpm. Four

separate nozzles discharge directly inside the core shroud. . . ."

In the original design of the RHR system, the LPCl injection flow path was

physically separate with no interconnection of piping from the RHR pumps to the

reactor vessel. The suction of the RHR pumps utilized separate suction strainers

from the suppression pool with individual suction isolation valves; however, a cross-

tie with dual manual isolation valves connected the suction supply lines. After

reviewing the pertinent design basis documentation, the inspector concluded that

i the modification installing the cross-tie between the discharge or injection paths,

( still adequately assured electrical separation of the independent LPCI subsystems;

however, the mechanical separation criteria were changed.

The licensee's 10 CFR 50.59 evaluations recognized this change and did properly

evaluate the potential for internal flooding events, etc., as a result of pipe breaks.  !

However, the 10 CFR 50.59 evaluations did not rigorously review the potential loss ,

of more than one LPCI flow path resulting from an erroneous valve alignment that I

'

could change the expected availability of the LPCI subsystems to respond to a

postulated LOCA event. Design Change Package Nos.1 and 2 of the DCP, which

installed the cross-tie between the "A" and "C" RHR injection loops, did not

consider a review of the ECCS TS when determining the acceptability of the design

change. Further, the 10 CFR 50.59 evaluation concluded that there was no

"Unreviewed Safety Question" due to the fact that " . . .neither the performance of

the systems required to mitigate the consequences of an accident is being changed,

nor are the initiating event mechanisms being changed. . .." While Package No. 3,

which installed the cross-tie between the "B" and "D" RHR injection loops, did

review the ECCS technical specifications, it still concluded that there was no

"Unreviewed Safety Question" on the same basis as stated in DCP Package Nos.1 ,

and 2. l

The inspector questioned with this conclusion because the DCP changed the design

of a system that is used to mitigate the consequences of an accident, namely, the

LPCl mode of the RHR system. Because the original design of the LPCI system had

no chance of two injection paths being cross-tied during an accident mitigation, the

probability of such an event after implementing the DCP may be greater. The

modification created a potential accident without an LPCIindependent injection flow

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path, if the respective isolation valves were erroneously left open during power  !'

operation. Further, the licensee's evaluations did not address the consequences of

such a malfunction of the LPCI system as could occur with the cross-tie valves

open during power operations.

After the inspector raised the concern about the inappropriate consideration of the

affect on the LPCI system, the licensee identified that the cross-tie valves should

probably have been considered part of the LPCI flow path for surveillance testing

per TS 4.5.1 (b). This surveillance demonstrates that the ECCS flow path valves

are in their correct position on a monthly basis, if not locked, sealed, or otherwise

secured in position. The applicable surveillance test procedures had not been

changed upon implementation of the DCP. However, the inspectors were informed I

that the valves were being visually observed on a monthly basis in order to satisfy

extended containment boundary procedure requirements that were changed to

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incorporate the DCP implementation.

The inspector concluded that the four,18 inch, cross-tie isolation valves should

have been considered part of the LPCI flow path. Failure to ensure that the ECCS

surveillance test procedure accurately reflected the actual design of the system was  :

viewed as a further indication of a weak engineering evaluation to support the DCP.

However, based on a review of the current standard technical specifications, as well ,

'as the technical specifications for the Limerick station that employs a similar design,

the inspector noted that RHR cross-tie isolation valves received specific surveillance

i

requirements beyond that of TS 4.5.1 (b). The standard technical specifications

required a monthly surveillance requirement specifically for the RHR cross-tie  !

isolation valves to ensure that they were closed and their motor operators de-

energized. The standard technical specification bases described that this  :

requirement ensured that the LPCIloops remained independent, so that a - -i

malfunction in one subsystem would not affect any other subsystem. Therefore,

the inspector was further concerned that the engineering evaluation for this i

modification should have identified the unreviewed safety question described above,  ;

and should have resulted in a technical specification change incorporating the

requirements of the standard technical specifications, or similar, for the LPCI cross- 7

tie isolation valves. This item is unresolved pending further NRC review. (UNR 50-

354/97-01-04)

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c. Conclusion  ;

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The inspector concluded that the licensee's implementation of Design Change

Package No. 4EC-3411 was, in part, based upon a weak 10 CFR 50.59 evaluation,  !

which indicated a weakness in the engineering development, review and approval

process of 10 CFR 50.59 evaluations to support design changes. The licensee's  !

evaluation failed to identify a potential unreviewed safety question and the need for  !

a technical specification change in order to implement the modification. Further,

since this DCP was implemented over the course of several years with different

parties involved in the 10 CFR 50.59 review and approval, it was further concluded -

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that numerous opportunities were available for the licensee to identify this problem.

While there may be an unreviewed safety question, the inspector verified that the i

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cross-tie isolation valves were properly installed, providing double isolation

capability; and, that the valves were being rnaintained closed ensuring the

independence of the LPCI subsystems. ,

!

The inspector also concluded that the DCP documentation was thorough. The i

observed portions of the completed field work indicated good installation

l implementation. Testing considerations were found appropriate and test completion

I was timely. l

!

E2 Engineering Support of Facilities and Equipment

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E2.1 Testable Check Valve Failures i

i l

l a. Insoection Scope (37551. 62707) l

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,

The inspectors reviewed PSE&G's response to a failed inservice test of the RCIC

system turbine exhaust check valve. The assessment included an evaluation of the

licensee's repc,rting of this event, short term corrective actions, and effectiveness of

corrective action program implementation.

b. Observations and Findinas

l On February 4,1997, operators declared the RCIC system inoperable following an

l inservice test failure of the associated system turbine exhaust check valve, a

testable 10" Anchor Darling swing check. During the test of this valve, the

l operators were unable to engage the valve disc with a cam that is attached to the

test handle. A subsequent internal inspection by maintenance technicians revealed

l that the cam, which is positioned on the valve disc hinge shaft with a set screw, -

I had slipped from its required position, rendering the valve untestable. Technicians

adjusted the cam position as required and fixed it in place with the set screw. The

valve was reassembled and the RCIC system was declared operable on February 5.

In part because operators reported this event per 10 CFR 50.72 as an unplanned

inoperability of a single train safety system, Hope Creek management assigned a

significance level 1 condition report to the engineering department to perform a

detailed root cause evaluation of the event. The inspectors interviewed the

responsible engineering personnel as well as the documented root cause l

determinations, along with recommended corrective actions. As a result of the

investigation, PSE&G determined that this same check valve had failed two times j

previously, in 1992 and 1995, for similar reasons. Additionally, the analogous high #

pressure coolant injection (HPCl) check valve had failed under these circumstances {

in 1989. l

!

The licensee's investigation concluded that a 1989 DCP which modified a

,

population of nearly 45 swing check valves with the test handle mechanism (to

j facilitate periodic inservice tests), failed to provide adequate technical guidance to  :

ensure that the set screw which secures the cam to the disc hinge shaft would I

l remain engaged. Specifically, though the modification concept included a provision

!

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to drill a recess in the hinge shaft to accept the set screw to prevent slippage, the

) implementation guidance did not adequately describe the need to perform this

i

activity. Additionally, the DCP failed to ensure that applicable component drawings

and maintenance procedures were updated to reflect the post-modification

configuration. Further, opportunities to identify and correct these deficiencies were  :

missed during the noted post-DCP implementation valve IST failures.

,

l The inspectors judged PSE&G's root cause evaluation as sufficiently thorough in

4 that it identified numerous contributing factors to this repeat event. Additionally,

} the inspectors verified that corrective actions were developed to ensure that

recurrence of this event would be precluded. ,Specifically, the RCIC turbine exhaust

]

check valve was modified during a March 5,1997 scheduled on-line system outage

, by drilling the recess in the valve's hinge shaft. Further, the HPCI turbine exhaust

l valve was to be inspected (and modified as necessary) in a system outage

4 scheduled for March 17,1997. The remaining potentially-affected check valve

i' population would be evaluated on a priority basis as associated system outage

opportunities became available. Maintenance procedures, component drawings, and

i other controlled documentation were being revised to reflect actual configurations.

Deficiencies in PSE&G's design change process and problem identification and

1 corrective action program prior to 1995 have been documented in detailin past NRC

inspection reports and licensee correspondence, including licensee event reports.

'

PSE&G has instituted numerous programmatic changes in both areas which have -

resulted in improved overall performance. As such, the inspectors agreed with *

1 PSE&G's current assessment that the self-revealing RCIC turbine exhaust check

,

valve IST failure event of February 4,1997 was largely the result of these past  :

programmatic problems, and likely would not have occurred under the new ,

guidance. i

.

a  !

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This event had minimal safety consequence since the valve did not experience a

functional failure and the RCIC system was not called upon to operate during it's

period of inoperability. In spite of this assessment, the inspectors concluded that

this recent event was indicative of a failure in 1995 (and before) to identify and

implement effective corrective actions to prevent this condition adverse to quality, a

violation of 10 CFR 50 Appendix B Criterion XVI, " Corrective Action." (VIO 50-

354/97-01-05)

c. Conclusions

A repeat failure of the RCIC system turbine exhaust check valve inservice test

highlighted past deficieacies in PSE&G's design change and configuration

management process, as well as weaknesses in the corrective action program.  ;

However, the recent effort to identify causal factors associated with this event and

develop lasting corrective actions was good.

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E2.2 " Permanent" Scaffoldina in Safetv-related Areas

a. Inspection Scope (37551)

The inspectors conducted a review of the adequacy of Hope Creek's implementation

of the PSE&G scaffolding control program. Plant walkdowns, procedure reviews,

and interviews with station personnel were conducted in forming the assessment. j

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b. Observations and Findinas

Hope Creek personnel administratively control scaffolding in the station using the

guidance specified in NC.NA-AP.ZZ-0023 (NAP-23), Sca//o/ ding and Transient

Loads Contro/. Revision 4, Section 5.1.8 of this guidance stipulates that all i

scaffolding is to be removed "in a timely manner after completion of the work l

activity" requiring the scaffold. The inspectors reviewed the scaffold control log i

and performed a plant walkdown to determine the adequacy of program l

implementation; numerous scaffold structures were discovered throughout the

station, in both safety and non safety-related areas which had been in place for over

two years, in fact, some work orders referenced in the scaffold control log were

generated in 1990. The inspectors questioned plant management whether  !

compliance with the guidance in NAP-23 was being achieved. Additionally, the l

inspectors questioned whether any " permanently" installed scaffolding in seismically-

qualified areas was appropriately constructed, evaluated, and inspected. l

l

As a direct result of these inquiries, Hope Creek management initiated a significance l

level 2 action rcquest in accordance with the corrective action program, and

chartered a comprehensive review of the station's scaffolding program to determine I

compliance with regulatcry and licensee requirements. PSE&G walkdowns I

identified numerous discrepancies, including: (1) lack of appropriate documentation

to support variances from scaffolding construction criteria, (2) equipment operability i

concerns due to inadequate clearances between scaffolding and safety-related I

systems (i.e. seismic II/I concerns), (3) inadequate periodic scaffolding inspections,

and (4) failure to adhere to NAP-23 guidance regarding timeliness of scaffolding

removal. All potential equipment / system operability concerns noted during the j

walkdowns were promptly corrected.

The inspectors noted that Hope Creek management exhibited prompt and

appropriate response to the concerns. Additionally, the discrepancies identified

were adequately documented in the corrective action program for significance

evaluation and ultimate resolution. In spite of this quality response, the inspectors

judged that the numerous issues involving control of scaffolding in safety-related I

areas demonstrated poor implementation of NAP-23 that persisted for an extended )

period. Additionally, PSE&G's failure to evaluate consistently the impact of the '

seismic II/l concerns induced by the installation of scaffolding in close proximity to

safety-related equipment was a violation of NAP-23. (VIO 50-354/97-01-06)  ;

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c. Conclusions

i

Poor implementation of established scaffolding control guidance enabled the

installation and retention of several scaffolds in safety-related areas including the

"A" and "B" residual heat removal pump rooms and the standby liquid control pump

room of the Hope Creek station without adequately evaluating the impact of these

structures on the design and licensing basis of the facility.

E8 Miscellaneous Engineering issues

E8.1 (Closed) LER 50-354/97-03: unplanned reactor core isolation cooling system 1

inoperability due to an inservice test failure of the turbine exhaust containment

isolation valve. This event is discussed in Section E2.1 of this report. No new

issues were revealed by this LER.  ;

!

E8.2 LClosed) LER 50-354/97-02: inconsistency between the FRVS technical

specifications and single failure criteria. On February 14,1997, the licensee

reported to the NRC that during a 10 CFR 50.59 evaluation, a condition was ,

identified where the current technical specifications would not assure that the

design requirements of the FRVS were met for all possible configurations. The plant

technical specifications require that only five of the six FRVS recirculation units be

operable; however, for such acceptable alignment with only five recirculation units

available, certain postulated accident sequences, including a loss of off site power j

and a single active failure of either the "A" or "B" EDGs, or a passive failure of one ]

of the SACS loops, could result in only three FRVS recirculation units being

'

available, which is less than the four assumed in the FSAR accident analysis. The

licensee determined that the non-conservative technical specification has been q

essentially unchanged since initial licensing. Further, it was determined that while  !

all of the FRVS recirculation units were operable at the time of discovery of this

issue, that prior operations with one of the units inoperable for indefinite periods

had occurred. The licensee determined that the non-conservative technical

specification was a result of a failure to consider single failure analysis during the

development of the FRVS technical specifications. Immediate corrective actions

included irnplementation of an administrative technical specification to assure a 7-

day Limiting Condition for Operation for any one FRVS recirculation unit being

inoperable, in addition, a technical specification amendment was being prepared to

correct the non-conservative technical specification. The inspectors concluded that

the licensee's evaluation and corrective actions were reasonable and complete for

this original design error. l

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E8.3 (Closed) LER 50-354/97-01: emergency diesel generator and fire suppression

system interaction results in the plant being in a condition outside of the design

basis. This issue was discussed in NRC Inspection Report 50-354/96-11 Section i

01.2 and NRC Inspection Report 50-354/96-09 Section E8.1. No new information I

was revealed in this LER.

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. E8.4 (Open) URI 50-354/96-04-06 and URI 50-354/96-09-02: On March 17,1997, the

licensee provided an update of committed corrective actions regarding the ultimate

heat sink fUHS) and its interfacing systems. During the design basis configuration ,

4 verifications of the station service water system (SSWS) and safety auxiliary cooling l

l water system (SACS), and the ongoing service water system operational

l performance inspection (SWSOPI) the following discrepancies were identified that  ;

impact the current technical specifications: (1) UHS temperature limits; (2) UHS

]) river water level limits; and, (3) SSWS and SACS operating configurations. To

j address these concerns and maintain operability of the UHS, SSWS and SACS, the

j. licensee has implemented a number of compensatory actions including -I

administrative operating limits on river water temperature and river water level. The I

inspector reviewed the actions and they appeared appropriate to maintain the

, affected systems operable or place the unit in a safe condition. The licensee

) expects that these issues will be resolved by April 30,1997, including submittal of

) new limiting conditions for operation as necessary. In addition, the licensee stated j

i

that the ongoing SWSOPl effort is expected to be completed by the end of the

second quarter of calendar year 1997.

,

IV. Plant Support

R2 Status of RP&C Facilities and Equipment

J

i The inspectors reviewed the license and technical specifications pertaining the

installed criticality monitoring instrumentation. The license was found to provide a )

specific exemption from the criticality alarm requirements of 10 CFR 70.24. Further

'

, the plant technical specifications ensured that the instrumentation was available and

l periodically tested. The inspector had no further questions regarding this matter. 1

1

i S2 Status of Security Facilities and Equipment

The inspector verified that associated security equipment was working properly or )

i had been appropriately compensated during high wind conditions that occurred at l

l the site on several occasions during the inspection period. The inspector noted that

the security force management had anticipated some difficulty in monitoring

I

I equipment performance and had called in additional security force personnel in order

'

to provide adequate compensation. The inspector had no concerns regarding this

issue.

l

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l F2 Status of Fire Protection Facilities and Equipment

F2.1 Periodic Testina of Emeraency Diesel Generator Ventilation Fire Damoers

.

'

a. Inspection Scone (61726. 62707. 71750)

. Based on FSAR and procedural reviews, as well as plant walkdowns and interviews

with fire protection and maintenance personnel, the inspectors evaluated the testing

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23

employed by PSE&G to maintain the EDG room ventilation fire dampers in an

operable condition,

b. Observations and Findinos

?

The Hope Creek FSAR describes the fire protection program and its implementation

at the station. The inspectors noted that FSAR section 9.5.1.4.2 specifically states

that carbon dioxide total flooding systems, such as that employed in the EDG

rooms, is subject to complete operational inspections and acceptance testing in

accordance with the National Fire Codes. An inspector review of NFPA 12 (the

industry standard for total flooding fire suppression systems) revealed that there is

little guidance for system functional testing of ventilation fire dampers.

in spite of the minimalindustry testing guidance, the inspectors determined that

PSE&G adequately tested the EDG room ventilation dampers. Procedures have been  !

'

developed and implemented to verify the function of each detection and actuation

circuit and to stroke each fire damper on a periodic basis. The inspectors also

noted, however, that the electrothermal links (ETL) which release the dampers and

allow them to operate have not been functionally tested since initial installation.

Based on interviews with fire protection engineers and a review of the ETL vendor

testing guidance, the inspectors determined that this practice was acceptable.

c. Conclusions

,

PSE&G appropriately tested the EDG room ventilation fire dampers and has ,

established appropriate controls to ensure this activity is completed on a periodic '

basis and in accordance with the program description in the FSAR. H

V. Manaaement Meetinas <

X1 Exit Meeting Summary ,

A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR

description highlighted the need for a special focused review that compares plant practices,

procedures and/or parameters to the UFSAR description. While performing the inspections

discussed in this report, the inspectors reviewed the applicable portions of the UFS All that

related to the areas inspected. The following inconsistencies were noted between the

wording of the UFSAR and the plant practices, procedures and/or parameters observed by

the inspectors. The RHR and LPCI system descriptions and design bases were found

inconsistent as it related to physical separation of the LPCl injection flow paths. This

matter was discussed in Section E1.1 of this report. Also, the SACS system process flow

drawing was found inconsistent with current operating procedures for correct valve line up.

This matter was discussed in Section 01.3 of this report.

The inspectors presented the inspection results to members of licensee management at the ,

conclusion of the inspection on March 27,1997. The licensee acknowledged the findings I

presented,

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The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified,

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INSPECTION PROCEDURES USED

l IP 37551: Onsite Engineering

)

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IP 61726: Surveillance Observations l

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IP 62707: Maintenance Observations

IP 71707: Plant Operations

i IP 71750: Plant Support Activities

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ITEMS OPENED, CLOSED, AND DISCUSSED

j Ooened

i

50-354/97-01-01 URI standby SACS loop operation

.

50-354/97-01-02 URI Agastat and Struthers-Dunn relay concerns

a

50-354/97-01-03 URI evaluation of adequacy of Hope Creek FRVS surveillance test ,

methodology ,j

50-354/97-01-04 URI adequacy of safety evaluation for RHR cross-tie

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50-354/97-01-05 VIO violation of 10 CFR '50 Appendix B Criterion XVI, " Corrective l

} Action" l

50-354/97-01-06 VIO seismic concerns induced by the installation of scaffolding  ;

1

Closed

'

50-354/97-01 LER EDG l

50-354/97-02 LER inconsistencies between FRVS T.S. and single failure criteria )

50-354/97-03 LER unplanned reactor core isolation cooling system reportability

50-354/97-04 LER "B" Division primary containment isolation

50-354/94-22-02 URI control room staffing issue

4 Discussed I

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i 50-354/96-04-06 URI station service water design basis concerns i

50-354/96-09-02 URI SACS design basis concern regarding pump runout

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LIST OF ACRONYMS USED

I

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CAP Corrective Action Program

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CAQs Conditions Adverse to Quality

CREF Control Room Effluent Filtration

3

DCP Design Change Package ,

j ECCS Emergency Core Cooling System '

. EDG Emergency Diesel Generator  :

1 ESF Engineered Safety Feature l

l ETL Electrothermal Links

FRVS Filtration, Recirculation, and Ventilation System

HPCI High Pressure Coolant injection

, HWCl Hydrogen Water Chemistry injection

j IRM Intermediate Range Monitor I

j LER Licensee Event Report

a LOCA Loss of Coolant Accident 1

LPCI Low Pressure Coolant injection  ;

i M&TE Measurement and Test Equipment  ;

j MSLRM Main Steam Line Radiation Monitors l

l NRC Nuclear Regulatory Commission

'

PDR Public Document Room ]

i

PSE&G Public Service Electric ard Gas

'

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QA/NSR Ouality Assurance / Nuclear Safety Review

, RCIC Reactor Coolant Isolation Cooling

j RHR Residual Heat Removal

l RHRHX Residual Heat Removal System Heat Exchanger  !

! SACS Safety Auxiliaries Cooling System I

j SSWS Station Service Water System l

! SWSOPl Service Water System Operational Performance Inspection .

TS Technical Specification

] UHS Ultimate Heat Sink i

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