Text

Insp Rept 50-354/97-02 on 970318-0428.Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support.Routine Insp of Physical Protection & Security Program Also Conducted
	ML20148D230
Person / Time
Site:	Hope Creek
Issue date:	05/23/1997
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20148D196	List: ML20148D191; ML20148D201; ML20148D230;
References
	50-354-97-02, 50-354-97-2, NUDOCS 9705300121
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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

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Docket No: 50-354

License Nos: NPF-57

Report No. 50-354/97-02

Licensee: Public Service Electric and Gas Company

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Facility: Hope Creek Nuclear Generating Station

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Location: P.O. Box 236

Hancocks Bridge, New Jersey 08038

Dates: March 18,1997 - April 28,1997

Inspectors: R. J. Summers, Senior Resident inspector

S. A. Morris, Resident inspector

G. C. Smith, Senior Physical Security inspector

E. B. King, Physical Security inspector

D. T. Moy, Reactor Engineer

J. D. Orr, Reactor Engineer

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

Division of Reactor Projects

9705300121 970523

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EXECUTIVE SUMMARY

Hope Creek Generating Station

NRC Inspection Report 50-354/97-02

This integrated inspection included aspects of licensee operations, engineering,

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

in addition, it includes the results of announced inspections by regional inspectors in the

areas of plant operations, physical protection and engineering support. A routine core

inspection of the security program was conducted during the period of March 17-21 and

April 14-17,1997. The conclusions and major assessment finding of that inspection are

contained in this report; however, the entire details of that inspection are contained in NRC

Inspection Report 50-272/97-07;50-311/97-07.

Operations

The inspectors concluded that operator response to the plant 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. (Section 01.2)

Operators safely operated the Hope Creek Station. However, the Nuclear Shift Supervisors

were challenged with a large number of administrative tasks not directly associated with

safe and reliable plant operation. The Nuclear Shift Supervisors did not review key plant

parameters as frequently as required by the Operations Standards. (Section 01.3)

The affects on human performance were not evaluated prior to implementing a schedule

that included work weeks of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months before a scheduled day off. (Section

01.3)

Plant operations department personnel effectively identified a potential emergency diesel

generator surveillance test pre-conditioning concern, and implemented prompt and

appropriate corrective actions to resolve the issue. (Section O2.1)

A non-licensed equipment operator error resulted in operation of an emergency diesel

generator at full load with half of the cylinder petcocks in the open position, indicating a

lack of attention to detail and inadequate independent verification of petcock position

following maintenance. An engineering evaluation to determine the potential impact of this

event on future engine operation was good. (Section 04.1)

Station operators exhibited good control of the plant during both planned evolutions and

unanticipated events. (Section 04.2)

The inspectors concluded that the licensee's use of performance monitoring was good and

provided valuable assessment data regarding both human performance and equipment

performance. (Section 08.1)

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Maintenance

The observed maintenance activities were conducted properly and indicated generally good

performance in adherence with station procedures. (Section M1.1)

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The inspectors identified several examples of minor degradation of the Hope Creek plant I

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paging system and concluded that existing programmatic controls to ensure that the

system remained in an acceptable condition were not fully effective. (Section M2.1)

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A safety auxiliaries cooling system temporary modification which replaced system crosstie

valves with blank flanges was adequately justified in an associated safety evaluation, and

was properly implemented in accordance with station procedures. (Section E2.1)

All current temporary modifications were appropriately scheduled for removal during or

before the next refueling outage. (Section E2.1) l

NRC inspectors discovered additional examples of inadequate implementation of the

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PSE&G scaffolding control program, indicating weaknesses in the immediate corrective

actions taken following the initial NRC identification of this concern. (Section E2.2)

i Plant Sucoort

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j The inspectors concluded that access to abandoned Unit 2 areas was positively controlled

and administered. Hope Creek management ensured that Unit 1 vital area boundaries were

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maintained and that no radioactive waste materials were stored in unauthorized locations.

', Housekeeping in the Unit 2 spaces was poor, yet did not appear to impact the material

condition of Unit 1 support equipment. (Section R1.1)

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i The inspector concluded that the licensee was maintaining the Radiation Monitor'.ng

l System (RMS) equipment properly as indicated by performance monitoring data review. In

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addition, it was also noted that the overall availability of the RMS was very good and

, showed much improvement over operations in 1995 and early 1996. (Section R2.2)

. The security program was determined to be adequate to protect public health and safety.

Appropriate corrective actions have been implemented to address previously identified

! weaknesses in the program. The alarm station operators were knowledgeable of their

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duties and responsibilities and security training was being performed in accordance with

l the NRC-approved training and qualification plan. Protected area detection equipment

i satisfied the NRC-approved Physical Security Plan (the Plan) commitments, security

equipment testing was being performed as required by the Plan, and maintenance of

i security equipment was being performed in a timely manner as evidenced by minimal

compensatory posting associated with security equipment repairs. Based on observations

and discussions with security officers, the inspectors determined that they possessed the

' requisite knowledge to carry out their assigned duties and that the training program wus

effective. As an addition to the inspection, the UFSAR initiative, Section 4.2.2 of the Plan

, titled, " Vehicle and Cargo Controls," was reviewed. The inspcctors determined, based on

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i discussions with security supervision, procedural reviews, and observations, that vehicles

! were being searched and controlled prior to entry into the protected area as described in

the Plan and applicable procedures. (Section S)

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TABLE OF CONTENTS

EXEC UTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TABLE O F CO NT ENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v ,

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1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

I I . M ai n t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

111. Engineering ................................................... 10- '

I V . Pl a n t S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

V. Management Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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Report Details

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Summarv of Plant Status

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

maintained throughout the inspection period spanning March 18,1997, through April 28,

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1997, except for a power reduction to 30 percent power on April 5 and 6 to r.apport

maintenance activities including a temporary repair to a steam leak on the high pressure

coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems' steam line drain

pots' common drain line in the steam tunnel; repair a steam leak on a moisture separator

instrument; and, repair the fast acting solenoid on the No. 2 main turbine stop valve.

Other minor power reductions occurred during the period to support maintenance and

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testing activities. At the end of the inspection period on April 28,1997, the reactor was

at 100 percent power, had operated continuously for 172 days, and was 134 days from

the beginning of its seventh refueling outage.

The licensee announced the following organizational changes during the inspection peiiod: '

On April 7,1997, the Nuclear Engineering Department was reorganized to have four

engincering directors reporting to the Senior Vice President of Engineering. The four

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directors were: Mark Reddemann, Director of Salem Design Engineering and Fuels; Mark

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McGough, Director of Plant Engineering and Projects; Gary Overbeck, Director of Hope

Creek and Component Engineering; and, Mike Rencheck, Director of Salem System

Engineering.

On April 17,1997, the Nuclear Business Unit was reorganized as follows: Leon Eliason,

Chief Nuclear Officer; L. Storz, Senior Vice President - Operations: E. Simpson, Senior Vice

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President - Engineering: J. McMahon, Director, Quality Assurance; and, E. Salowitz,

Director, Business Support. Among the changes in the organization responsibilities were:

creating a new organization and director position for Salem Unit 1 Recovery; moving the

Licensing function and organization into the Nuclear Engineering organization from the

former Quality Assurance / Nuclear Safety Review (QA/NSR) & Licensing organization;

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consolidating the planning functicn into the Business Support organization; and,

consolidating the maintenance organizations for both Salem and Hope Creek into a tingle !

support organization. Key personnel assignments within the new organization were: J.

Benjamin, Director, Salem Unit 1 Recovery; M. Trum, General Manager, NBU Maintenance;

and, D. Crouch, Manager, Maintenance & Construction Planning.

1. Operations

01 Conduct of Operations

01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of

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

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

the sections below.

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01.2 Operator Response to Events

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

first event involved the high pressure coolant injection (HPCI) system being declared

inoperable on March 22,1997, due to an unexpected closure of its steam supply

line containment isolation valve during system testing. Additional information on

this event and the licensee's corrective actions are found in Section M8.1 of this

report. The second event involved a report of degraded equipment (Struthers-Dunn

219 NE Series relays) necessary for accident mitigation on April 7,1997.

Additional information on this event and the licensee's corrective actions can be

found in Section M2.3 of NRC IR 50-354/97-01 and Section M8.2 of this report.

The third event involved a licensee notification of a minor oil spill to the State of

1 New Jersey Department of Environmental Protection. The inspectors concluded

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that this last event was considered minor and no additional information is provided

in this report. The inspectois further concluded that operator response to the events !

was' good, in that the necessary immediate actions were taken; the events were l

i properly classified in accordance with the licensee's Event Classification Guide

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

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01.3 Extended Control Room Observations

a. Insoection Scoce (71715)

An inspector performed an extended control room observation to evaluate the

impact of Hope Creek's low Senior Reactor Operator (SRO) shift manning levels.

The inspector focused on SRO on-shift activities.

b. Observations and Findinas

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Hope Creek implemented a new schedule for on-shift SRO's on March 14,1997.

The intent of this new schedule Was to alleviate scheduling difficulties associated

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with vacation and low SRO shift manning levels. The new schedule is based on a

10 week cycle and a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months snift. This new schedule includes a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and a 60

hour work week once every 10 week cycle. As an example, Crew E SROs are

scheduled to work 6 night shifts starting May 10,1997, followed by 3 days off,

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and then followed by 5 night shifts before another day off. The previous schedule

required on-shift SRO's to work no more than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to a scheduled day off.

4 The inspector noted that the new schedule includes wcrk weeks that are an

exception to the nominal work week schedule definsa in Hope Creek Technical

Specification (T.S.) 6.2.2.. T.S. 6.2.2 in part requires that operating personnel

work a nominal 40-hour week while the unit is operating. Hope Creek Technical

Specifications further define the shift schedule to be based upon a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shift

with a work week of either 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months or 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . Hope Creek senior management

is taken exception to the nominal 40 hour4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months work week described in T.S. 6.2.2 due to

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the low SRO shift manning levels. Hope Creek senior management considers the

low SRO shift manning levels to be an unforeseen problem requiring overtime above

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the nominal 40 hour4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months week. T.S. 6.2.2 in part allows the use of overtime in the

event of unforeseen problems.

The inspector was concerned that Hope Creek did not evaluate the potential affects

' on human performance prior to implementing the new schedule, especially during

the extended work weeks of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . The inspector reviewed time

sheets for the on-shift SHOs from October 3,1996 through March 14' 1997 and he ,

verified the working hours to be within T.S. 6.2.2 requirements.

It appeared to the inspector that Nuclear Shift Supervisors (NSS) did not meet the

Operations Standards by not reviewing key plant parameters at least once per hour.

The inspector observed Nuclear Control Operators (NCO) monitoring panels as j

described by the Operations Standards. The inspector observed other instances

where control room personnel did not meet the Operations Standards. The %nior I

Nuclear Shift Supervisor (SNSS) and NSS often leaned on the inner horseshoe

. panels while conducting turnover.in the outer horseshoe area. Food was displayed

on the NCO's desk for extended periods. Personnel not assigned to the shift,

including Operations senior management, consumed food in the control room. It

appeared 14 the inspector that the Senior Nuclear Shift Supervisor did not enforce

these Operations Standards.

The inspector interviewed six on-shift SROs. Each SRO interviewed indicated a

concern with the administrative duties required of the Nuclear Shift Supervisor. The ;

' SROs feel that they are challenged to prevent administrative activities from _ i

distracting their safe' operation of the unit. It appeared to the inspector that the

NSSs spent excessive time on the computer involved with work control processes

and especially the action request process. The Operations Manager is considering-

alternatives to alleviate some of the significant administrative duties of the Nuclear

Shift Supervisor. The Operations Manager intends to add two licensed operators to

the Operations Support Staff. Full time clerical support has ben assigned to support

the Control Room. Operators interviewed considered this a significant

improvement.

The inspector observed both the SNSS and NSS to engage in activities in the NSS

Office. The NSS Office is within the control room boundary defined by Station

Operating Practices. However, the NSS Office is not in audible range of the reactor

operator at the co,1 trois nor in audible range of the control room annunciators. If

the SRO in the control room is not in audible range, he must remain in sight of the

reactor operator at the controls in accordance with Station Operating Practices.

The inspector observed both the SNSS and NSS simultaneously engage in activities

in the NSS Office and neither individual visually monitored the control room.

The inspector observed the use of " peer check" to be frequent and adequate. " Peer

check," as mentioned in this report, refers to a human performance initiative

wherein a second individual verifies correct equipment manipulation before any

action is performed.

The inspector identified a discrepancy between the Hope Creek Updated Final

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! Safety Analysis Report (UFSAR) Section 8.3.1.1.3.10 and the Hope Creek standard

operating procedure, Emergency Diesei Generators Operation (HC.OP-SO.KJ-

0001(Q) Rev. 26). The UFSAR requires specific action to be taken after an

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emergency diesel generator operates longer than four hours at less than 20 percent

' rated load. Hope Creek does not track cumulative unloaded time and the actions for

i extended operation at light load conflict with the UFSAR. The licensee initiated an

Action Request to track this issue to resolution.

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The inspector noted headphones and cables stored in a control room panel during

the performance of a seismic monitor surveillance. The licensee promptly removed

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the headphones and cables and initiated an Action Request,

c. Conclusions

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l_ Operators safely operated the Hope Creek Station. However, the Nuclear Shift i

!_ Supervisors were challenged with a large number of administrative tasks not directly

j. associated with safe and reliable plant operation. The Nuclear Shift Supervisors did

! not review key plant parameters as frequently as required by.the Operations

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Standards. The affects on human performance were not evaluated prior to

j implementing a schedule that included work weeks of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months before

a scheduled day off.

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{ 02 Operational Status of Facilities and Equipment

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02.1 Pre-Conditionina of Emeraency Diesel Generator Air Start Valves

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l a. Insoection Scooe (62707,61726)

[ The inspectors evaluated the Hope Creek operations department response to an

l' industry operating experience feedback issue involving pre-conditioning of

i emergency diesel generator (EDG) air start valves.

b. Observations and Findinas

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On April 10,1997, operations department staff personnel determined that the

!- manner in which Hope Creek operators prepared the EDG's for monthly operability l

h surveillance testing was similar to the process employed by another nuclear utility i

{ . which had recently been issued a Notice of Violation for preconditioning the engine

j for successful testing. Specifically, operators typically "bar-over" the EDG's using

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l the air start system to implement a vendor recommendation to remove accumulated

moisture in the engine cylinders when the machine has not been operated within the

j. ' previous 7 days.- However, as a result of the industry experience, operations and

engineering department management appropriately concluded that the Hope Creek

practice constituted pre-conditioning the air start valves, effectively nullifying the

j validity of the subsequent surveillance test. As a result, the operations department

i issued a " night order" to the operating shifts to ensure that, until this concern could

4 be fully evaluated, all EDG pre-start evolutions would include barring-over the '

engines using a an alternate air supply.

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The inspectors observed that operations personnel appropriately entered this issue

into the station's corrective action program for condition evaluation, reportability

review, and corrective action development. Additionally, the inspectors witnessed

operations training department instructors in the field with equipment operators

demonstrating the use of the alternate air supply and EDG manual barring device.

The inspectors questioned whether this issue should have been identified earlier as

part of the recently completed Technical Specification Surveillance improvement

Project (TSSIP). However, it was subsequently determined that finding an issue of

this nature, i.e. potential pre-conditioning mechanisms, was outside the scope of

the TSSIP review,

c. Conclusions

Plant operations department personnel effectively identified a potential emergency

diesel generator surveillance test pre-conditioning concern, and implemented prompt

and appropriate corrective actions to resolve the issue.

04 Operator Knowledge and Performance

04.1 Observation of "C" Emeroency Diesel Generator Surveillance Test

a. Insoection Scoce (61726)

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The inspectors witnessed a periodic technical specification surveillance test of the

"C" Emergency Diesel Generator (EDG). Interviews with the personnel responsible

for implementing and supervising the activity were conducted, as was a detailed

test procedure review.

b. Observations and Findinas

On April 23,1997, the inspectors observed plant equipment operators (EO)

completing the field portions of surveillance test procedure HC.OP-ST.KJ-0003(Q)

for the "C" EDG. This test was required to implement the requirements of TS 4.8.1.1.2. Three different EOs were assigned to perform various portions of the

field activities. One of the pre-startup activities required to support EDG test

operation involved "barring-over" the engine with air to remove moisture which may

have accumulated in the cylinders. At Hope Creek, small petcocks installed on each

of the 12 EDG cylinders are installed which, if opened, permit compressed gaces in j

the cylinders to vent to the room housing the engine. By procedure EOs open then I

close these petcocks during the barring-over process to ensure moisture is

eliminated.

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Prior to engine start, the inspectors verified that the barring-over process was l

completed by reviewing the field copy of the test procedure and by questioning the

EOs. However, once control room operators started and fully loaded the "C" EDG, I

it was evident that some of the petcocks had been left in the open position because

of smoke and unusual noise emanating from one side of the engine. The field EOs

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promptly recognized that 6 of the 12 petcocks had been left open and closed them

without incident. The responsible EO, a relatively new employee, drafted an action

request in accordance with the corrective action program to document the

occurrence.

The inspectors discussed the implications of this event with cognizant station

operators and managers, including a discussion of a similar event which occurred on

this same EDG in February of 1996 (see NRC Inspection Report 50-354/96-80).

Additionally, the inspectors reviewed the fact finding summary completed by the

operations department to validate stated causal factors, safety significance, and

generic implications. The inspectors agreed with PSE&G's assertion that the event

was caused by human error (inattention to detail, inadequate skills or knowledge,

lack of experience), but further judged that this error was clearly a failure to adhere l

to the operating procedure for barring-over the EDG. Further the inspectors l

quesDned the lack of independent verification of petcock position following '

operation. The inspectort, noted that operations management conducted i

coaching / counseling sessions with the responsible individual, and reinforced I

expectations for procedural adherence before allowing him to resume shift

responsibilities. Additionally, station personnel were evaluedng the need for

independent verification and/or whether a " peer check" process was necessary to

ensure that future petcock operations would be correct.

The "C" EDG surveillance was completed satisfactorily, and a post-event

engineering analysis concluded that operating the EDG at fullload with 6 petcocks

open did not result in any consequence to the machine. However, the inspectors

judged that the failure to shut the EDG cylinder petcocks following pre-startup

evolutions constituted a violation of HC.OP-SO.KJ-0001(Q), "EDG System

Operation" (VIO 50-354/97-02-01).

c. Conclusions

A non-licensed equipment operator error resulted in operation of an emergency

diesel generator at fullload with half of the cylinder petcocks in the open position,

indicating a lack of attention to detail and inadequate independent verification of

petcock position following operation. An engineering evaluation to determine the

potential impact of this event on future engine operation was good.

04.2 Ooerations Shift Performance Observations I

The inspectors observed control room operators and equipment operators in the I

field respond to various transient events at the station, both planned and unplanned.

Specifically, the inspectors witnessed unplanned trips of the "A" control room

ventilation system and the "A" control rod drive hydraulic pump, the latter of which

led to several control rod hydraulic control unit accumulator low pressure alarms.

Additionally, pre-planned transfers of reactor protection system power supplies and

steam jet air ejectors were observed. Both of these evolutions had the potential to

induce significant plant transients if performed incorrectly, Finally, the inspectors

observed operators conduct a significant plant power reduction to support emergent

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corrective maintenance in the steam tunnel. l

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The inspectors noted that in all cases, operators appropriately employed the

procedural guidance applicable for each event or evolution. Good command and

control of the evolutions were evident. Operators logs accurately reflected each of

the events / evolutions after they were completed. Overhead alarms were promptly

acknowledged and evaluated. Technical specification action statement entries were

. made as required. Where appropriate, operators initiated action requests in

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accordance with the PSE&G corrective action program to determine root cauces and

corrective actions.

Station operators exhibited good control of the plant during both planned evolutions

and unanticipated events.

08 Miscellaneous Operations issue

08.1 Operations Performance Monitorina

The inspectors reviewed the licensee's current performance monitoring practices

and observed regular management discussions based on the performance

monitoring indications. The licensee frequently discusses the aggregate impact of

plant deficiencies and assesses the nature of the deficiencies to ensure that

corrective actions are timely and effective. The inspector noted that the

performance monitoring indicators show some improvement in reducing control

room deficiencies. However, other indicators, such as the " cumulative unplanned

LCO hours indicator," show some weakness in schedule adherence by plant

personnel and an increasing equipment failure rate. Overall, the inspector concluded

that the licensee's use of performance monitoring was good and provided valuable

assessment data regarding both human performance and equipment performance.

II. Maintenance

M1 Conduct of Maintenance !

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M 1.1 General Comments '

a. insoection Scoce (62707. 61726)

The inspectors observed all or portions of the following maintenance and ,

surveillance activities: i

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HPCl/RCIC common drain pot drain line temporary leak repair by

encapsulation

"B" reactor protection system (RPS) motor-generator set repair

"A" service water system (SWS) pump replacement and screen repair

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"E" filtration, recire, and ventilation system (FRVS) " Hiller" valve replacement

Agastat and Struthers-Dunn relay replacements

"B" steam Jet air ejector (SJAE) pressure control valve emergent repair

"A" control rod drive (CRD) pump troubleshooting

"C" emergency diesel generator (EDG) 184-day surveillance test

b. Observations and Findinas

Except for the previously noted problem noted with observed equipment operator

performance during the conduct of the "C" EDG 184-day surveillance test (see

Section 04.1), the inspector observed generally good work coordination between ,

operations, radiation protection, maintenance and engineering departments in the I

conduct of the above activities. For example, good ALARA practices were l

observed for the encapsulation of the HPCl/RCIC drain line that was leaking into the

steam tunnel. Also, good Station Operations Review Committee (SORC) reviews of ;

the proposed temporary repair method and development of specific monitoring !

conditions for the degraded pipe and its affect on nearby safety-related equipment

were observed by the inspectors.

c. Conclusions - l

The inspectors concluded that the observed maintenance activities were conducted l

properly and indicated generally good performance in adherence with station

procedures.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 - Dearadation of the Plant Paaina (Gai-Tronics) System

During routine tours of the Hope Creek station, the inspectors noted several areas

of the plant in which it was difficult to hear station-wide plant page '

announcements. Subsequent investigation resulted in the identification of several

paging system speakers that were either not functioning or were barely audible.

Individual action requests were drafted to initiate work orders to correct each of the

deficiencies noted by the inspectors. However, after the inspectors raised the

possibility of a potential programmatic concern with respect to paging system

monitoring and maintenance, station management initiated a level 2 condition report

to evaluate the full extent of the condition and to develop any necessary corrective i

actions.

The inspectors reviewed the UFSAR section which describes the Hope Creek paging

system operation and design basis. Wnile information regarding system monitoring l

and maintenance was not specific, in general the inspectors concluded that the -

station was maintaining the system in an adequate condition. Station management l

agreed that more stringent programmatic controls for ensuring that the paging

system remained fully functional were necessary.

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The inspectors identified several examples of minor degradation of the Hope Creek

plant paging system and concluded that existing programmatic controls to ensure

that the system remained in an acceptable condition were not fully effective.

M8 Miscellaneous Maintenance issues

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M8.1 (Closed) LER 50-354/97-06: High Pressure Coolant injection isolation Due to

Personnel Error During Functional Testing. This event involved an automatic

isolation of the HPCI system steam line containment isolation valve that occurred on i

March 22,1997 during the performance of a scheduled functional test of the high !

drywell pressure instrumentation. Based on the licensee investigation into the I

cause of this event, it was determined that the technician conducting the

aforementioned test erroneously inserted test leads into a test point associated with l

the HPCI isolation logic causing the event. This test point was located just above l

the test point that the technician was supposed to use. The licensee's corrective

'

actions included: restoring the isolated HPCI system to proper lineup; reporting the

event to the NRC via both 10 CFR 50.72 and 10 CFR 50.73, as required; taking

appropriate disciplinary action with involved personnel; and, communicating the

nature of the event with all station personnel, as well as conducting specific

lessons-learned training with l&C technicians. The inspector concluded that the

licensee's actions promptly corrected this procedure adherence inadequacy. This

licensee identified and corrected violation is being treated as a Non-Cited Violation,

consistent with Section Vll.B.1 of the NRC Enforcement Poliev.

M8.2 LOcen) URI 50-354/97-01-02: The licensee informed the NRC of potential failure of

Struthers-Dunn 219 NE series relays, used in a variety of safety-related applications

at the plant. The licensee had observed an increasing trend in failures and then

identified that the failures were related to wrong or missing bearing pad materials

leading to thermal degradation and ultimate failure of the components. On April 23,

1997, the licensee provided additional information regarding observations of the

affected relays to NRC representatives for vendor inspection and event assessment

and generic communications. The licensee stated that it planned to submit an LER ,

about this concern in early May 1997. The inspector concluded that the licensee's I

efforts to date were comprehensive. The licensee confirmed the failure mechanism

and failure modes with the vendor and have taken appropriate action to ensure that

affected relays in safety-related applications are known to be functional. This

matter remains open pending review of the licensee's planned LER submittal.

M8.3 {Q. pen) LER 50-354/97-05 and URI 50-354/97-01-04: Operation in a Technical

Specification Prohibited Condition due to Failure to Perform Monthly Flowpath

Verification Surveillance Checks of the Residual Heat Removal (RHR) System

Crosstie Valves. This event documents part of the licensee evaluation of an NRC

identified concern with a modification to the RHR system providing crosstie

flowpaths for the "C" and "D" RHR pumps. This concern is identified in Section

E1.1 of NRC IR 50-354/97-01. This LER specifically addresses the fact that after

implementation of the modification to the "C" RHR subsystem in 1994, the licensee

failed to revise appropriate surveillance and operating procedures to ensure that the

associated low pressure coolant injection (LPCI) flowpath was maintained properly.

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Failure to ensure the flowpath alignment was considered by the licensee to be a

violation of technical specification surveillance requirements. The LER further

described that this condition was corrected in December 1995 when the crosstie

isolation valve was locked closed. The inspector noted that additional evaluations

of this problem were in progress at the close of the inspection period. The

inspector considered this matter to be open pending further NRC review of the

crosstie modification package.

M8.4 (Closed) LER 50-354/95-033. Sucolement 14 and VIO 50-354/95-11-02: Technical

Specification Surveillance Requirement Implementation Deficiencies. This final

supplemental report documents the last findings of the licensee's Technical

Specification Surveillance Improvement Program (TSSIP). The TSSIP identified two

additional surveillance deficiencies associated with the containment hydrogen

recombiner system and the rod block monitor. Both surveillance deficiencies were

corrected by performance of appropriate testing; however, additional modifications

were necessary to fully resolve the rod block monitor concerns. Overall, the

inspectors concluded that the licensee actions to identify and correct the

surveillance test deficiencies were broad and comprehensive. The conditions

leading to the violation cited in NRC IR 50-354/95-11 have been fully evaluated by

the licensee and corrected. The surveillance test procedures have been corrected to

ensure that the technical specification surveillance requirements were being

appropriately implemented. The inspector concluded that the licensee's corrective

actions were reasonable and complete.

Ill. Enaineerina

E2 Engineering Support of Facilities and Equipment

E2.1 Safety Auxiliaries Coolina System Temocrary Modification

a. Insoection Scope (37551)

The inspectors performed a detailed review of a temporary modification recently

installed in the safety auxiliaries cooling system (SACS). This review included an

assessment of the associated 10 CFR 50.59 safety evaluation, documents and

drawings which describe the operation of the affected system, and an in-plant

walkddown of the modified components. Additionally, the number and status of all

active temporary modifications at Hope Creek were reviewed

b. Observations and Findinas

Hope Creek personnel installed temporary modification 96-023 in the SACS system

on March 21,1997, which replaced two spent fuel pool cooling system heat

exchanger crosstie valves (1EGV-545 and 1EGV-547) with blank flanges. PSE&G

deemed this modification necessary to minimize the " sluicing" effect between the

two independent SACS loops caused by excessive valve seat ic:Aege. The

inspectors independently reviewed the safety evaluation that justified

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implementation of this modification, and judged that it satisfied the requirements of

10 CFR 50.59 and the licensee internal " Control of Temporary Modifications"

procedure NA.NC-AP.ZZ-0013(Q).

In addition to the safety evaluation review, the inspectors verified that the affected

piping and instrumentation drawings were revised to reflect the modified system

configuration. Finally, field implementation of the modification was appropriate and

was conspicuously labeled as temporary. The temporary modification log in the

Hope Creek work control center also correctly tracked this modification. The

inspectors noted that this modification would have to be removed prior to spent fuel

pool operations in the upcoming refueling outage in order to support the planned full

core offload.

The inspectors observed that at the close of the reporting period, there were 24

active temporary modifications installed at the station,17 of which were l

implemented subsequent to the last refueling outage. The oldest temporary J

modification, involving water intrusion into the primary containment instrument gas )

system, was installed in September 1994. The inspectors noted that all of the

modifications were scheduled for removal before or during the next refueling

outage.

c. Conclusions

A safety auxiliaries cooling system temporary modification which replaced system

crosstie valves with blank flanges was adequately justified in an associate safety

evaluation, and was properly implemented in accordance with station procedures.

.

Additionally, all current temporary modifications were appropriately scheduled for

removal during or before the next refueling outage.

E2.2 Follow Up to Previousiv identified Temocrary Structure Control Problems (Open) VIO i

50-354/97-01-05 I

a. Insoection Scoce (37551. 92903)

The inspectors conducted follow up reviews of Hope Creek's scaffolding control

program to determine the effectiveness of short term corrective actions stemming

from previously identified concerns. The NRC isaued a Notice of Violation in

inspection Report 50-354/97-01 for inadequate controls associated with scaffold

implementation and tracking,

b. Observations and Findinas

PSE&G's immediate response to the violation regarding effective control of

temporary scaffolding, documented in detail in Inspection Report 50-354/97-01, in

part included a detailed walkdown of all accessible areas at the station to locate

installed scaffolding, and a " roll out" to all maintenance and engineering personnel

reinforcing the expectation that internal administrative controls for scaffolding be

effectively implemented. However, during a reactor building walkdown on April 14,

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1997, several weeks after initially identifying the problems, the inspectors

discovered additional examples of inadequate scaffold control and implementation.

Additionally, unlike the original concerns, the inspectors identified scaffolding

installed in the plant which was used for equipment protection and for structural

support for temporary lead shielding which was not tracked or inspected as required

by PSE&G's administrative control procedure, NA.NC-AP.ZZ-0023 (NAP-23).

The inspectors met with station engineering management to discuss the newly

identified issues. During this discussion PSE&G indicated that it had validated the

inspectors recent findings, and admitted that the short term actions implemented

subsequent to the initial findings were ineffective. Engineering management stated

that most of the newly identified scaffolds with inadequate controls were

constructed following initial communication of the concerns nearly one month prior.

As a result, Hope Creek management upgraded the condition report which tracked

this issue from a level 2 (determine apparent cause) to a level 1 (detailed root cause

analysis). All the newly discovered problems were promptly corrected. Further,

PSE&G as a whole planned to centralize the scaffold construction and control

function in an effort the better control the efficiency and consistency of the

program.

The inspectors considered the scaffolding construction and control problems

identified subsequent to the initial findings as additional examples of the same 1

violation cited in the NRC Inspection Report noted above; specifically, PSE&G )

personnel failed to implement adequately the requirements of NAP-23. l

c. Conclusions

NRC inspectors discovered additional examples of inadequate implementation of the

PSE&G scaffolding control program, indicating weaknesses in the immediate

corrective actions taken following the initial NRC identification of this concern.

E8 Miscellaneous Engineering issues

E8.1 Licensee Service Water System Ooerational Performance insoection:

a. Insoection Scope 40501

A region-based inspector observed portions of the licensee's Service Water System

Operational Performance Inspection (SWSOPI). The licensee's evaluation of the

safety auxiliary cooling system (SACS) was not yet complete,

b. Observations and Findinas

The inspector noted the following: (1) SWS analyses were detailed; (2) recent root

cause analyses were thorough; and, (3) previous engineering self-assessments on

SWS had identified many of the issues found during the SWSOPl.

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Most notably, the licensee's self-assessment tearn found that: (1) corrective actions

implemented to monitor for SWS strainer problems were not effective; (2) the

implementation of corrective actions from past self-assessments were not in all

cases complete and timely; (3) performance monitoring for the SACS heat I

exchangers was weak; (4) instances of inadequate 10 CFR 50.59 safety

evaluations; and, (5) some weaknesses in configuration control for design

calculations.

c. Conclusions

The inspector concluded that the licensee's SWSOPl self assessment effort, to date

was thorough. Further NRC observation of the SACS portion of the self-assessment

is on going.

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IV. Plant Support 1

R1 Radiological Protection and Chemistry (RP&C) Controls

R1.1 Walk Down of (Abandoned) Hooe Creek Unit 2 Spaces

On April 28,1997, the inspectors conducted a comprehensive tour of abandoned

Hope Creek Unit 2 buildings to verify that these areas were not being used for

unauthorized radioactive waste storage and that vital area boundaries to Unit 1

spaces were adequately posted and controlled. Housekeeping and material

condition of Unit 1 support equipment in the Unit 2 spaces were also evaluated.

. The inspectors did not identify any areas of the Unit 2 facility that contained

radioactive waste material. There were some areas of Unit 2 that required

radiologically controlled area postings because of radiation fields induced by the

Unit 1 offgas system; these postings were deemed adequate. Further, all of the

Unit 1 vital area boundaries which interfaced with Unit 2 structures wcre adequately

posted and positively secured. Housekeeping in all of the Unit 2 areas was poor, in

stark contrast to the conditions typically observed in the occupied Unit 1 spaces.

Most of the debris in the areas was left over from initial construction, in spite of

this assessment, the inspectors judged that none of the Unit 1 support equipment

located in Unit 2 spaces (e.g. auxiliary boiler steam, telecommunications wiring and

junction boxes, etc.) would likely be affected by the adverse conditions.

Additionally, none of the noted Unit 1 support equipment was classified as safety-

related.

The inspectors noted that access to the Unit 2 spaces was effectively controlled in

that relatively few senior PSE&G individuals had keys to associated door locks.

Additionally, a current station administrative procedure provided positive controls to

ensure that all personnel entries into the Unit 2 spaces would be conducted safely.

The inspectors concluded that access to abandoned Unit 2 areas was positively

controlled and administered. Hope Creek management ensured that Unit 1 vital

14

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area boundaries were maintained and that no radioactive waste materials were

stored in unauthorized locations. Housekeeping in the Unit 2 spaces was poor, yet

did not appear to impt e the material condition of Unit 1 support equipment.

R2 Status of RP&C Facilitit - J Equipment

R2.1 Revised TLD Guidelines

On April 1,1997, the licensee revised the TLD guidelines at the site. The new

guidelines now rouuire allindividuals with radiological controlled area (RCA) access

to be issued a ' O. All radiation workers will be required to wear their TLD and en

electronic dosimeter while in the RCA. The inspector observed personnel in the

RCA after implementation of these new guidelines and found their performance

acceptable.

R2.2 Radiation Monitorina System (RMS) Performance Indicators

The inspector reviewed the licensee's RIVS performance indicators to ascertain that

the licensee was properly maintaining the equipment available for process

monitoring of effluents. The inspector observed that, except for the South Plant

Vent RMS, that all effluent monitors were being maintained available in excess of

95 percent available. The South Plant Vent RMS annual average was in excess of

85 percent available; however, some of this out-of-service time was necessary to

implement improvements to the system. The inspector concluded that the licensee

was maintaining the equipment properly as indicated by the performance

monitoring. In addition, the inspector noted that the overall availability of the RMS

was very good and showed much improvement over operations in 1995 and early

1996.

P5 Staff Training and Qualification in EP

P5.1 Unannounced Off-hours Callout Trainino Drill Cr...gue rieview

The inspector reviewed the subject critique, dated April 16,1997, to ascertain that

the critique assessed performance of the drill responders appropriately and provided

reasonable assurance that performance objectives were met. The inspector noted

that the critique provided an overall assessment that drill performance met

expectations. There were a few areas identified requiring corrective actions or

improvements; but, none of these items were considered significant by the

inspector. Overall, the licensee's drill conduct was good and the inspector

considered this activity as providing good traing for the responders.

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i S1 Conduct of Security and Safeguards Activities

A routine core inspection of the security program was conducted by Messrs. G. C.

Smith and E. B. King during the period of March 17-21 and April 14-17,1997.

Areas inspected included: previously identified items; protected area barriers and

detection aids; alarm stations and communications; testing, maintenance and

compensatory measures; training and qualification; organization and administration;

quality assurance; and security and safeguards activities. The security inspection

feeder report was integrated into the Salem routine resident inspection report, IR

50-272/97-07 50-311/97-07. The conclusions and overall executive summary

assessment from that inspection are included in this inspection report, however, the

supporting inspection details are documented in the referenced Salem inspection

report only.

The inspectors determined that the licensee was conducting its security and

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safeguards activities in a manner that protected public health and safety.

S2 Status of Security Facilities and Equipment

On April 16,1997, the inspectors determined by observation, that the actions taken

by the licensee to correct the concern were adequate. The inspectors determined

that the height of the Protected Area Barrier (PAB) satisfied the requirements of the

Plan and that the intrusion Detection Systems (IDSs) were functional and effective,

and were installed and maintained as described in the Plan.

The inspectors determined by discussions with the Central Alarm Station / Secondary

Alarm Station (CAS/SAS) operators on April 16,1997, that the actions taken by the

licensee to reiterate expectations concerning alarm assessment were effective. The

determination was based on the CAS/SAS operators' responses to the inspectors'

questioning. The CAS/SAS operators were knowledgeable of their alarm

assessment responsibilities and the alarm stations and communications met the

licensee's Plan commitments and NRC requirements.

Documentation on file, reviewed April 16,1997, confirmed that security equipment

was being tested and maintained as required; however, failures of search equipment

were not being documented in the test records. The licensee agreed to change its

practice to allow for tracking and trending of equipment failures found during

testing. Repair work was timely and the use of compensatory measures was found

to be appropriate and minimal.

SS Security and Safeguards Staff Training and Qualification

The inspectors determined that training had been conducted in accordance with the

Training and Qualification (T&O) Plan. Based on the Security Force Members'

(SFM) responses to the inspectors' questions and the inspectors' observations, the

training provided by the security training staff was considered effective.

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S6 Security Organization and Administration

Management support for the physica! security program was determined to be

adequate. No problems with se eganizational structure that would be detrimental

to the effective implementation of the security and safeguards programs were

observed or reported.

S7 Quality Assurance in Security and Safeguards Activities

The inspectors concluded that the self-assessment program in place to identify,

prevent and resolve potential problems was weak and an improved self-assessment

program would enhance program effectiveness.

The review concluded that the audit was comprehensive in scope and depth, that

the findings were appropriately distributed and addressed and that the audit

program was being properly administered.

S8 Misce!Ianeous Security and Safeguards issues

S81. (Closed) Insoection Followuo item 50-272. 50-311. 50-354/93-28-01 - Review the

effectiveness of assessment aids after upgrade is complete. The program to

upgrade the assessment aids has been completed and the assessment aids were

determined to be adequate to perform their intended function.

S8.2 (Closed) Violation 50-272, 50-311, 50-354/96-10-03 - Failure to control

badge /keycards and failure to display photo badges in the protected area. The

inspectors verified the corrective actions described in the licensee's recponse letter,

dated February 26,1997, to be reasonable and complete and they were found to be

properly implemented. No similar problems were identified.

S8.3 (Closed) Violation 50-272. 50-311, 50-354/EA96-344-01013 - Failure to exercise

positive access control over photo badge keycards thereby creating the opportunity

for unauthorized access to the vital areas. The inspectors verified that corrective

actions described in the licensee's response to letter, dated January 10,1997, to

be reasonable and complete and they were found to be properly implemented. No

ML20148D230

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