ML20216B127

Insp Rept 50-443/97-08 on 971212-980131.No Violations Noted. Major Areas Inspected:Aspects of Licensee Operations, Engineering,Maint & Plant Support

ML20216B127
Person / Time
Site:	Seabrook
Issue date:	02/27/1998
From:	Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20216B119	List: ML20216B114 ML20216B127
References
50-443-97-08, 50-443-97-8, NUDOCS 9803120416
Download: ML20216B127 (23)

See also: IR 05000443/1997008

Text

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( U. S. NUCLEAR REGULATORY COMMISSION

REGION I

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Docket No.: 50-443

License No.: NPF-86

Report No.: 50-443/97-08

Licensee: North Atlantic Energy Service Corporation 1

Facility: Seabrook Generating Station, Unit 1 j

Location: Post Office Box 300

Seabrook, New Hampshire 03874

Dates: December 12,1997 - January 31,1998

Inspectors: Raymond K. Lorson, Senior Resident inspector

Javier Brand, Resident inspector Intern

Harold Gray, Senior Reactor Engineer, Division of Reactor Safety

Approved by: Curtis J. Cowgill,' Chief, Projects Branch 5

Division of Reactor Projects

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9903120416 980227 ,

PDR ADOCK 05000443 l

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EXECUTIVE SUMMARY

Seabrook Generating Station, Unit 1 i

NRC Inspection Report 50-443/97-08

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers an eight week period of resident and

specialist inspection activities. I

Ooerations:

• The operators responded well to control reactor parameters during shutdown and

start-up conditions. Station and operations management established strong

equipment mode change controls. The operators responded promptly and

effectively to an unexpected loss of the CBA system.

• The inspectors noted a number of minor material deficiencies that had not been j

identified by the station staff for correction. The number of deficiencies identified

indicated inconsistent standards for material condition. The licensee was taking

action to raise the standards for material condition.

• The preliminary findings from the three event teams formed during the period were

broad and thorough, and provided clear actions to be completed prior to the plant

mode change.

Maintenance:

• The residual heat removal (RHR) system pipe replacement activities were performed

well. Foreign material exclusion controls during the control building air conditioning

(CBA) system modifications were poor, and the actions taken to improve

performance in this area were not fully effective. The cold shutdown in-service test

program requirements were met during the forced outage.

• The emergency feedwater (EFW) surveillance activities were performed well. A

weakness was noted involving the effectiveness of previous actions to repair the

pump discharge pressure gage oscillations. In addition, several minor procedural

format weaknesses were identified. The licensee is reviewing this issue.

• The apparent cause evaluation report for six looso service water valve flange nuts

did not document an apparent root cause. The failure to properly document

apparent cause findings could affect the identification and correction of the

underlying causes for deficiencies. This issue will remain unresolved (Unresolved

item 50-443/97-08-01).

Enaineering:

• The plant was operated for a significant period of time with the SI-V-131 valve open

to mitigate the consequences of reactor coolant isolation check valve leakage. This

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configuration rendered the A safety injection (SI) pump inoperable. The licensee's

initial evaluation of this condition did not consider all the potential ultrasonic flow

measurement instrument inaccuracies. This condition appeared to be a violation of

Technical Specification (TS) 3.5.2, and 10 CFR 50 Appendix B Criterion XVI

(Escalated Enforcement item (eel 50-443/97-08-02).

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o The inspector did not identify any factors that would provide a' basis for disagreeing

with the Event Team finding that the RHR pipe leaks were a result of stress

corrosion cracking initiated from the outside of the pipe from chlorides leached on to

the pipe from the heat insulating material.

e The licensee did not promptly investigate potential pressure boundary leakage from

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RHR pipe located below the RC-V-89 relief valve. This is an apparent violation of

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! 10 CFR 50 Appendix B Criterion XVI (eel 50-443/97-08-03).

e The licensee did not implement prompt timely corrective actions to address the root

causes of CBA compressor failures that have occurred since 1993. This

subsequently resulted in plant operation in October and December with less thar,

the TS 3.7.6 required two CBA compressors operable. This is an apparent violation

of TS 3.7.6, and 10 CFR 50 Appendix B Criterion XVI (eel 50-443/97-08-04).

e Several performance weaknesses were identified regarding the implementation of

the oil analysis program. Incorrect information was provided to the shift manager

which formed the basis for the decision to delay sampling the 28 charging pump

motor bearing oil. The motor oil was subsequently sampled and found not to

adversely affect the pump operability, and the oil sampling frequency was increased

to better monitor the oil condition (Unresolved Item 50-443/97-08-05).

e Prompt corrective actions were not implemented for a degraded positive

displacement charging system pump. This is an apparent violation of 10 CFR 50 l

Appendix B Criterion XVI (eel 50-443/97-08-06).

Plant Suonort:

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e The radiological controls technicians at the RCA checkpoint and in the field were  ;

attentive and provided high quality assistance to ensure proper radiological work j

practices. All personnel observed were properly wearing dosimetry and protective

clothing as required. The licensee began to report the daily work group exposures

at the station management meeting to heighten personnel exposure awareness.

e The inspector concluded that the licensee's actions in response to a positive test

result were consistent with the fitness for duty program.

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TABLE OF CONTENTS

E X EC UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TA BLE O F C O NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

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

01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.1 General Comments (71707) ...........................1

02 Operational Status of Facilities and Equipment ...................1

02.1. Identification Of Equipment Deficiencies . . . . . . . . . . . . . . . . . . . 1

04 Operator Knowledge and Performance (71707) . . . . . . . . . . . . . . . . . . . 2

04.1 Operator Control Of Plant Parameters ....................2

07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

07.1 Event Team Investigations .. .........................3

11. Maintenance . . . . ..............................................3

M1 Conduct of Maintenance (62707/61726) . . . . . . . . . . . . . . . . . . . . . . . 3

M 1.1 Forced Outage Activities .............................3

M1.2 Surveillance Observation (EFW Turbine Driven Pump) . . . . . . . . . . 4

M7 Quality Assurance in Maintenar,ce Activities . . . . . . . . . . . . . . . . . . . . . 5

M7.1 Service Water Valve Loose Bolts . . . . . . . . . . . . . . . . . . . . . . . . 5

li l . Engi ne e ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

E1 Conduct Of Engineering (37751) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

E1.1 Safety injection Pump Flow Calculation . . . . . . . . . . . . . . . . . . . 6

E2 Engineering Support Of Facilities And Equipment (37551,40500) . . . . . . 8

E2.1 Residual Heat Removal Pipe Leaks Near Train "B" RC-V-89 Relief

V al v e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

E2.2 Control Building Air Conditioning System Performance ....... 10

E2.3 2B Chcrging Pump Motor Lubricating Oil Condition .......... 12

- E2.4 Positive Displacement Charging Pump Oil Leak . . . . . . . . . . . . . 13

E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

F 8.1 (Closed) LER 50-443/97-018-00: Control Room Air Conditioning

inoperability .....................................14

E8.2 (Closed) LER 50-443/97-015-00:Potentially Non-Conservative Fuel

Rod Performance Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

E8.3 (Closed) LER 50-443/94-08-00,and 50-443/94-08-01:Non-

Compliance With Technical Specification 3.8.4.2 Action Requirements

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IV. Plant Support ................................................14

R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . . . . . . 14

R1.1 General Com ments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

S1 Conduct of Security and Safeguards Activities . . . . . . . . . ........ 15

S1.1 General Comrnent (71707,71750) .....................15

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I' P7 Quality Assurance in Security and Safeguards Activities ...... 15

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P7.1 Fitness For Duty Test Results . . . . . . . . . . . . . . . . . . . . . . . . . 15

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V. M anage ment Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

X1 Exit Meeting Sum m ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

X3 Other N RC Activities . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . 16

PARTIAL LIST OF PERSON 3 CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i 7

INSPECTION PROCEDU RES US ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

IT.7MS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

LIST O F AC RO NYM S U S ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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Rencrt Details

Summarv of F[ ant Status

_ The inspection period began with the unit shutdown to replace a degraded section of

residual beat removal (RHR) system piping (Section E2.1). The RHR system was restored

. and the operators performed a reactor heatup to Mode 4 (Hot Shutdown) on December 15,

1997.. The licensee subsequently declared both' control building air conditioning (CBA)

system compressors inoperable, entered Technical Specification (TS) 3.0.3, and returned

the unit to Mode 5 (Cold Shutdown) on December 16,1997 (Section E2.2). The licensee

implemented several modifications designed to improve the CBA system performance,

performed a reactor start-up on January 16,1998, and reached full power on January 18,

1996. The unit oporated essentially at full power for the remainder of the period.

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1. Operations

01 Conduct of Operations  :

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01.1 General Comments (71707)

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

ongoing plant operations. In general, routine operations were performed in i

accordance with station procedures and plant evolutions were completed in a

deliberate manner with clear communications and effective oversight by shift .

supervision. Control room logs accurately reflected plant activities and observed

shift turnovers were comprehensive and thoroughly addressed questions posed by

the oncoming crew. Control room operators displayed good questioning  ;

perspectives prior to releasing work activities for field implementation. The l

inspectors found that operators were knowledgeable of pla-t and system status. l

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02 Operational Status of Facilities and Uquipment l

02.1 Identification Of Equipment Deficiencies

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a. Insoection Scone (71707,62707)

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The inspectors routinely conducted independent plant tours and we'kdowns of

selected portions of the primary auxiliary building, primary containment, emergency i

diesel generator, service water, and emergency feedwater system buildings. These

activities cor'sisted of the verification that safety-related system configurations,

power supplies, process parameters, support systems, and operational status were

consistent with TS requirements and the Updated Final Safety Analysis Report

. (UFSAR) descriptions. Additionally, system, component, and general area material

conditions and housekeeping status were noted.

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b.~ Observations and Findinas j

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The inspectors observed a number of minor equipment deficiencies involving boric

acid and lubricating oil leaks, minimal valve packing nut thread engsgement,

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insulation and stewage deficiencies that had not buen identified by the licensee for - l

' correction. Although these issues were minor in nature, they demonstrated

inconsistent standards by station personnel towards the identification of equipment

deficiencies. The inspectors discussed this concern with the Operations Manager

who agreed with this issue and was taking action to raise the standards for material

condition. Additionally, Site Management issued a memorandum on December 23,

1997 directing station personnel to maintain a questioning attitude and to formally

document probloms. The inspector will continue to review progress in this area.  ;

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c. Conclusions  !

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The inspectors noted a number of minor material deficiencies that had rd been  !

identified by the station staff. The number of deficiencies identified indicated

inconsistent standards among station personnel for material condition. The licensee

was taking action to raise standards for material condition.

04 Operator Knowledge and Performance (71707) I

04.1 Operator Control Of Plant Parameters i

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a. Insoection Scoos (71707)

The inspector reviewed operator performance during routine and non-routine

conditions including: control of reactor parameters while shutdown, the reactor

start-up, and in response to an unexpected loss of both CBA compressors on

January 1,1998.  ;

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b. Observations and Findinas  !

The operators maintained very good control of key reactor parameters while

shutdown, and during the reactor start-up on January 16,1998. Operations and i

station management enforced strong mode change controls to ensure that required  ;

systems and equipment were properly restored prior to start-up. During the start-

up, the inspectors observed that communications, procedural adherence, and

control of trainees 'were performed well. Additionally, the inspector noted that I

adequate controls were established for the dedicated safety injection (SI) system I

test header return line isolation valve (SI-V-131) operator consistent with NRC

Generic Letter 91-18.

The operators responded well to mitigate the effects of an unexpected loss of the

CBA system on January 1,1998. The operators promptly secured unnecessary

control room equipment as & acted by the abnormal operating procedure, and

obtained maintenance assistance to restore the CBA system within about six hours.

The impector observed that control room instrumentation operated properly, and

the wtrol room temperature increased slightly from 72 F to about 75.5 F before

lowering. The control room temperature did not exceed the TS 3.7.10

requirements.

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c. . Egpclusions

The operators responded well to control rest, tor parameters during shutdown and

start-up condit.ons. Station and operations management established strong

equipment mode change controls. The operator responded promptly and effectively

to an unexpected loss of the CBA system.

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07.1 Event Team investigations j

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Station management formed three event teams dving the forced outage to review

the operating history associated with the degraded RHR system pipe, the CBA

system, and also to review the practices and requirements for venting the t

emergency core cooling systems during operation. The inspector reviewed the  !

preliminary findings from each event team and noted that the reviews were broad

and thorough, and provided clear actions to be completed prior to the plant mode

change. The event team findings were discussed at the daily station management

meeting, and Station Management critically reviewed the event team findings.

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M1 Conduct of Maintenance (62707/61726)  ;

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M1.1 Forced Outage Activities

a. Insoection Scone (62707): l

The inspectors reviewed the maintenance activities associated with the forced- i

outage including: repair of the RHR system pipe, installation and testing of the CBA '

system modifications in accordance with design change request (DCR)94-025, and

cold shutdown in-service testing.

b.~ Observations and Findinas

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The inspectors observed the preparation of the new RHR pipe weld-o-let, and fit-up

of the replacement piping. The inspectors noted that the work activities were

. performed in accordance with applicable engineering instructions arid that the  !

maintenance technicians were knowledgeable of the tasks. No deficiencies were

noted during these observations.

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The licensee identified that foreign material exclusion (FME) controls were poor at

! the beginnine of the CBA system modifications. A solenoiri valve failure during

!- post-modification testing was attiibuted to foreign materiN internal to the valve.

-The licensee performed a standown and conducting training on FME controls and

standards. Subsequently, the inspector observed a poor FME practice during the

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fabrication of the tubing that was connected to the discharge of the oil separators.

The inspector identified his concern to the contract services field supervision who

corrected the individual. The inspector concluded that the licensee actions to

ensure good FME cond a were not fully effective.

The inspector interviewed a program support engineer and learned that all cold

shutdown in-service valve testing (IST) had been completed except for the testing

which required securing of all reactor coolant pumps. The inspector concluded that

the program requirements for cold shutdown IST testing had been satisfied.

c. Conclusions ,

The RHR pipe replacement activities were performed well. Foreign material

exclusion controls during the control building air conditioning system modifications

were poor. Licensee actions to improve performance in this area were not fully )

effective. The cold shutdown in-service test program requirements were met during j

the forced outage.

M1.2 Surveillance Observation (EFW Torbine Driven Pump)

a. Insoection Scone

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On January 15, the inspector observed the turbine driven emergency feedwater

pump (EFW) post cold shutdown test. The test is performed using operations

procedure OX1436.13, following a cold shutdown of greater than 30 days, to verify

the operability of the flow path to each steam generator, and the operability of the

check valves in the steam supply header. The inspector reviewed the surveillance

procedure, the Updated Final Safety Analysis Report (UFSAR), Technical

Specifications (TS), instrument calibration data, and reviewed the test results.

b. Observations and Findinas

The surveillance procedure was performed satisfactorily and the TS acceptance

criteria were met. Field personnel and control room operators communicated and

coordinated the test activities well. The check valve stroke and system flow

requirements were satisfied. In addition, the inspector verified other test

parameters such as turbine speed, and pump suction and discharge pressures.

Mea.;uring and test equipment (M&TE) were verified to be in current calibration.

The inspector noted that repairs performed in November 1997, to dampen pump

discharge pressure indicator (PI-4248) fluctuations had not been effective, and the

gage oscillated between 1560 and 1620 psig. The inspector notified the system

engineer of the continuing gage oscillations, and the maintenance technicians

subsequently rep! aced a snubber pin to suppress the oscillations. The licensee has

scheduled a post-maintenance inspection of the gage during the next pump

. operability test run.

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Seabrook's policy requires the midpoint to be used as the reading of a fluctuating

gage. However, in this case the midpoint (1590 psig) exceeded a procedural

discharge pressure limit of 1585 psig. This limit is one of the secondary indications

used to confirm that a potential EFW pump overheating condition does not exist

when the EFW recirculation flow indicator is not available. The inspector verified

that the other secondary parameters used to confirm adequate pump conditions

such as vibration, suction pressure, and lube oil cooler valve position, were met.

The inspector noted the following minor surveillance procedure weaknesses:

• A note was used to implement the action of verifying that a minimum flow of

greater thon 222 gpm was maintained.

• The same note provided several secondary parameta to review when the

primary flow indicator was not available. However, tae note did not specify

whether all or only one of the parameters was required to be verified.

• The procedure did not specify any required actions when the required

minimum flow of greater than 222 gpm was not met.

The inspector discussed these procedure weaknesses with the procedure

coordinator, who agreed to perform a review and to implement changes as required.

c. Concluc. ion

The EFW surveillance activities were performed well. A weakness was noted

involving the effectiveness of previous actions to repair the pump discharge

pressure gage oscillations. In addition, several minor procedural format weaknesses

were identified. The licensee is reviewing this issue. The inspecto? had no further

questions.

M7 Quality Assurance in Maintenance Activities

M7.1 Service Water Valve Loose Bolts

The inspector reviewed the apparent cause evaluation for adverse condition report

(ACR) 97-2381, discovered on November 6,1997, involving six loose flange nuts

on a service water valve. The inspector noted that the evaluation report, which had

been reviewed and accepted by the management review team (MRT), had not

identified an apparent root cause for the event. The inspector discussed this issue

with the corrective actions program manager who agreed that the apparent root

cause was not documented in the report,' but indicated that the MRT had considered

human error as the most likely cause for this event. The inspector agreed that

human error was the most likely cause for the loose nuts, but was concerned that

the failure to properly document the root cause investigation and MRT conclusions

cc,uld negatively impact the ability to identify and correct the underlying causes for

deficiencies. The inspector will review additional apparent cause reports to

determine if this repcrt documentation issue is an isolated corrective action program

deficiency. (Inspector Followup item (IFl) 97-08-01)

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Ill. Enoineerina

E1 Conduct Of Engineering (37751)

51.1 Safety injection Pump Flow Calculation

a. Insoection Scoce:

The inspector 'eviewed engineering calculation (C-S-1-84103) which the licensee

performed to evaluate opening tPa safety injection (SI) test header return isolation

valve (St V-131). Opening this vaive provided a flowpath to direct reactor coolant

(RC) system leakage through the reactor coolant isolation check valves to the

primary drain tank. The licensee initiated the Si system lineup change en October

21,1997, and terminated it on December 6,1997. Additionally, the operators had

established a similar Silineup from August 6 to August 8,1997, as discussed in

NRC Inspection Report 97-04.

The inspector also reviewed the licensee's response to adverse condition report

(ACR) 98-0105 which questioned the use of clamp-on ultrasonic flow measurement

devices to obtain the emergency core cooling system (ECCS) flow performance

data.

b. Observations and Findinas:

The lice.snsee calculated the A Si pump flowrate following an assumed failure of the

B tre:n solid state protection system (SSPS). The SSPS failure would render the B

01 pump and the SI-V131 automatic closing function inoperable resulting in a

condition where the A SI pump would be required to supply both the SI system Dow

and also the flow through the open SI-V131 valve. The calculation also assumed

fa;iure of the non-nuclear safety piping located immediately downstream of SI-V-

131. The licensee determined, for these conditions, that the A Si pump would be l

capable of supplving the TS required SI system flowrate of 419 gpm through the

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three most restrictive cold leg injection lines while not exceeding the TS pump

runout limit of 669 gpm.

A mechanical design engineer modeled this condition using system design

parameters as well as data measured during the June 1997 Si system cold leg flow

testing, The model was used to define the system operating curve which the

engineer then used to graphically determine the maximum and minimum system

flow values. The inspector independently reviewed the calculation and key input

assumptions using applicable drawings, Si system test data, and standard

engineering references. The inspector concluded that the method used to perform

the calculation was acceptable, but identified the following issues:

• The calculated maximum A Si pump flow (665gpm) was close to the TS

pump runout limit (669 gpm) and the int,pector questioned whether the

graphical method provided a sufficient level of accuracy.

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The SI pump data had been obtained during factory testing performed in

1977 end no allewance had been made for pump degradation.

The licensee addressec' these issues by performing an informal calculation that used

a more precise analytical method for determining the maximum A Sl pump flowrate

and incorporated the A Si pump data obtained during the Si system start-up testing.

The results of this calculation indicated that the A Si pump performance was still

acceptable. However, the calculated flow thorough the three most restrictive cold

leg injection lines decreased to about 420 gpm. The inspector discussed the above

issues with the Mechanical Engineering Manager who agreed to review the guidance

for selecting design input parameters.

The licensee initiated ACR 98-0105 that questioned the reportability and accuracy

of the clamp-on ultrasonic flow instruments used to collect the system flow data

during the June 1997 Si system testing. While reviewing this ACR, an

instrumentation and controls engineer identified that the ultrasonic flow instrument 4

output could be affected by minor variations in the pipe wall thickness.' The l

ultrasonic flow instruments in question had been calibrated based on a nominal pipe I

wall thickness instead of the actual pipe wall thickness. The licensee investigated

this concern with the instrument vendor and developed an analytical model to

account for the differences between the nominal and actual pipe sizes.

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The licensee measured the actual pipe wall thickness in the locations where the l

ultrasonic instruments had been connected to obtain the Si data. These i

measurements were then incorporated into the analytical model discussed above to

correct the SI system flow test data. The calculated maximum SI pump flow rate

(assuming SI-V-131 was shut) was 667.9 gpm, which did not exceed the TS limit

of 669.  !

Operating with the SI-V-131 valve open would result in approximately an additional

20 gpm of pump flow or a total pump flow of about 688 gpm which exceeded the

TS limit of 669 gpm and also the pump vendor runout limit of 675 gpm. The ,

licensee concluded that the A Si pump was inoperable during the periods when the l

SI-V131 valve was left open and unattended, and reported this condition on

January 22,1998, per 10 CFR 50.72, as a condition that could have prevented the i

fulfillment of the safety function of structures or systems that are needed to  !

mitigate the consequences of an accident.

Technical Specification 3.5.2 requires, in part, that two independent Si pumps be

maintained operable while in Modes 1,2, or 3. Contrary to the above, while

operating in Mode 1, the licensee did not maintain the A Si pump operable from

August 6 to August 9,1997, and from October 21, to December 6,1997. This in

an apparent violation of TS 3.5.2 (Escalated Enforcement item (eel) 50-443/97-08-

02).

Appendix B Criteri XVI requires, in part, that conditions adverse to quality be

promptly identifii a si corrected. The licensee opened SI-V-131 to redirect reactor

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coolant isolation check valve leakage to the primary drain tank to prevent the

undesired boron dilution of the Si ac'cumulators. This corrective action was

inadequate because it rendered the A Si pump inoperable, and is an apparent

violation of 10 CFR 50, Appendix B, Criterion XVI (eel 50-443/97 08-02). Other

examples were noted in Sections E2.1, E2.2, and E2.4 where corrective actions for

degraded equipment conditions were not prompt or effective.

During start-up from the forcsd outage, the RC system leakage continued, and the

licensee elected to station a dedicated watchstander to permit opening of the SI-

V131 without declaring the A SI pump inoperable. The inspector confirrned that the

licensee established appropriate controls for this watch as discussed in NRC

Generic Letter 91-18. The RC system lei igo has recently decreased and the >

licensee is currently operating with SI-V131 shut.

c. Conclusions: ,

Operation with the SI-V131 valve opc 1 rendered the A SI pump inoperable. The.

licensee's initial evaluation of this condition did not consider all the potential

sources of ultrasonic flow measurement instrument inaccuracies. The licensee's

actions following the discovery of the flow instrumentation inaccuracies have been  ;

appropriate.

E2 Engineering Support Of Facilities And Equipment (37551,40500)

E2.1 Residual Heat Rsmoval Pipe Leaks Near Train "B" RC-V-89 Relief Valve ,

a. Insoection Scoos

On December 5,1997, the site staff identified four small, weep size leaks on a 5

inch long, 3 inch diameter section of Type 304 stainless steel pipe near the train j

"B" residual heat removal pump suction relief valve (RC-V-89). The licensee formed '

an Event Team with objectives that included, finding the cause of the leaks,

evaluation of preleak history and conditions, develop the proper repair . method, l

establish near and long term corrective actions, and determine the system i

operability. The NRC conducted an inspection of the Event Team activities and  !

verified selected conditions and issues related to the root cause analysis,

subsequent repair and corrective actions. Nr.C attention was directed to the quality

of the original welds in the vicinity of the leaks, and the relation of leaks identified

in RHR welds F0316 and F0104 in 1987 (ref. NRC reports 50-443/87-16,88-06

and 89-08) to the leaks found in 1997. The NRC inspection included observations

of the failed pipe section and the replacement components. The inspector also

reviewed the relevant radiographs of nearby welds, replacement welds,

metallurgical and chemistry reports, the ':387 vintage RHR leaks, the corrective

actions established by the Event Team, progress made on the corrective actions and

the Event team written evaluation report for ACR 97-2579.

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b. Observatbns and Findinas

The licensee Event Team review of the original construction radiographs in the

vicinity of the pipe leaks showed no anomalies in the weld or base metal. One weld

was a shop weld and the other was a field weld, made by different welders at

different times. The metallurgical and chemistry work provided an adequate basis

for the conclusion that the leaks were the result of stress corrosion cracking

initiated from the outside of the pipe that progressed to the inside surface. NRC

radiographic review confirmed there were no adverse construction weld quality

problems such as cracks, perosity or weld slag shown on the pipe weid radiographs

in the vicinity of the leaks or on the similar welds on the "A" RHR train. Chemistry

analysis and photomicrographs showed the pipe material to be Type 304 stainless

steel.

In August 1987, fatigue cracks resulting in leaks were found next to RHR fillet

welds F0104 and F0316. The NRC reports 50-443/87-16,88-06 and 89-08 that I

discuss these leaks and their significance were reviewed. The site work requests

87-006260and 87-006501 for the repair of these welds were abo reviewed.

These two weld leaks were a result of fatigue induced cracking in lines that were

necessary for the startup and test process and had no relation to the leaks in 1997

near the RHR fv'-V-89 welds.

Unresolved item 97-07-01 discussed whether the licensee had previous

opportunities to identify and correct the RHR pipe leak. The licensee had been

aware of the boric acid residue external to the pipe wrap material since et least

November 1996. However, the licensee did not remove the pipe wrap material to

positively identify the source of this residue until December 5,1997. During the

intervening period station personnel including: engineers, supervisors, maintenance

and health physics technicians had been aware of this condition.

The licensee had multiple opportunities to identify this condition. For examp'e,

during the June 1997 refueling outsge, the licensee planned to remove insuir sn

and inspect this section of piping. However, this activity did not occur. This error

was detected by the SE around June 15,1997, who informed his supervisor that

the desired work activity had not been completed. However, no adverse condition

report was generated, and no actions were taken to remove the insulation and

inspect the pipe prior to the start-up on Juns 26.

Appenoix B Criterion XVI requires, in part, that adverse conditions ars promptly

identified and corrected. Contrary to the above the licensee took over a year to

fully investigate evidence of pressure boundary leakage from the RHR pipe below

the RC-V-89 relief valve. This resulted in plant operation with pressure boundary

leakage from an'AMSE Class 2 component. Other examples were noted in Sections

E1.1, E2.2, and E2.4 where corrective actions for equipment deficiencies were not

prompt or effective. This is an apparent violation of 10 CFR 50 Appendix B,

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Criterion XVI. Unresolved item 97-07-01 is closed, and this issue will be reviewed

alon1 with the apparent violation (eel 50-443/7-08-03).

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c. Conclusions

LThis inspection did 'not identify any factors that would provide a basis for

disagreeing with the Event Team finding that the leaks were a result of stress

corrosion cracking initiated from the outside of the pipe from chlorides leached on to

the pipe from the heat insulating material.

The licensee did not promptly investigate and correct evidence of potential pressure

boundary leakage from RHR pipe located below the RC-V-89 relief valve.

E2.2 Control Building Air Conditioning System Performance

a. Insoection Scooe:

The inspector reviewed the performance of the control building air conditioning

(CBA) system and the licensee's' actions to address long-standing system

operational problems,

b. Observations and Findinos:

On December 16,1997, the operators entered TS 3.0.3, made a one hour non-

emergency event report per 10 CFR 50.72, and returned the plant to Mode 5 from

Mode 4 after declaring both control building air conditioning (CBA) compressors

inoperable. The CBA compressors ar7 required to cool ' critical instruments within

the control room envelope for up tt er ty days following a postulated accident.

.The CBA compressors have had a history of operational problems as documented in

NRC Inspection Report 97-07, Licensee Event Report 97-018-00, and the licensee's

CBA event team evaluation report.

The licansee completed an engineering evaluation in 1994 to address a 1993 CBA

compressor failure. That evaluation resulted in development of design change

request 94-025 to correct the root cause(s) for the compressor failure which

included: loss of bearing lubrication caused by refrigerant contamination of the

lubricating oil, and/or refrigerant slugging to the cylinder piston assembly. The

modification was scheduled to be implemented in the third quarter of 1996.

However, it was delayed several times and not implemented until after the B CBA

compressor failure on December 16,1997. Multiple compressor failures have

occurred since 1993. However, the corrective actions have been focused on

component replacement rather than correcting the root'cause(s) for the failures.

Appendix B Criterion XVI of 10 CFR 50 requires, in part, that measures be

established to assure that conditions adverse to quality are promptly identified and

corrected. Contrary to the above, prompt corrective actions were . lot implemented

to address the root cause(s) for a history of CBA system compressor failures dating

back to 1993. Other examples were noted in Sections E1.1, E2.1, and E2.4 where

corrective actions for degraded equipment conditions were prompt or effective. The

failure to implement prompt corrective actions has resulted in multiple compressor j

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failures since 1993, and is an apparent violation of 10 CFR 50, Appendix B Criterion

XVI (eel 50443/97-08-04).

Several recent CBA compressor failures have occurred within thirty days after the

licensee replaced the compressor and declared the CBA system operable. For

example:

• The A CBA compressor was replaced on October 1,1997, and subsequently

failed on October 15,1997.

• On November 25, the B CBA compressor failed, and it subsequently failed

again and required replacement on December 7,1997.

• The B CBA compressor failed again on Decembcr 15,1997. However, the

plant was in Moda 6 during much of this period. I

Because the compressors failed in less than the required thirty day design basis

operating time, and the licensee failed to correct the root causes for the initial

f ailures, the irispector concluded that the licensee had improperly declared the CBA

compressors operable in October and December 1997. Technical Specification 3.7.6 requires that two independent control room emergency makeup air and

filtration subsystems (CREMAFS) be maintained operable. The CBA compressors

are required to maintain the CREMAFS system operable. Contrary to the above,

two independent CREMAFS subsystems were not maintained operable from October

1 to October 15, and from November 25 to December 7,1997. This is an apparent i

violation of TS 3.7.6 (eel 50-443/97-08-G4).

The licensee installed DCR 94-025 in January 1998 to correct the root causes for

the CBA compressor failures. The modification was designed to improve the control

of refrigerant through the system, and provide better separation of the refrigerant

and oil by installation of a head pressure control package, oil separation filters, and ,

a sightglass to improve monitoring of refrigerant levels. The incpector will continue i

to monitor CBA system performance.

c. Conclusions:

The licensee did not promptly implem.,..: corrective actions to address the root

cause(s) for a history of CBA compressor failures that have occurred since 1993.

The licensee implemented DCR 94-025 which addressed the root causes for the j

compressor failures. j

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E2.3 28 Charging Pump Motor Lubricating Oil Condition

a. Insoection ScooeL

On January, 26,1998,the shift manager requested that system engineering

evaluate.whether foreign material discovered in the 2B coolant charging pump

inboard motor bearing sightglass affected the pump operability. The charging

pumps provide the safety related high pressure injection function, and are required

to be operable per Technical Specification (TS) 3.5.2. The inspector evaluated the

licensee's response to this issue, visually inspected the motor lubricating oil,

interviewed the system engineer (SE) and sliift manager, and reviewed applicable

documentation.  !

b. Observations and Findinas:

The 2B charging pump had been operating since November 21, and was used for i

inventory control during the forced outage. On December 12, while the Unit was in

Mode 5, an auxiliary operator identified that the 2B charging pump inboard anotor

. bearing oil was discolored and contained foreign material (four small particles). The

operators initiated work request (WR) 97 WOO 3860to sample and replace the oil.

The SE reviewed the pump operating parametsrs (i.e. vibration, temperature,.

discharge pressure and flow) and determined that the pump was operable and

scheduled the oil sample to be drawn in March 1998. The inspector reviewed this

data and noted that the pump operating paramoters were acceptable but questioned

whether the oil should have been sampled promptly to confirm that the degraded oil

condition did not affect the pump operability.

The inspector learned, during follow-up discussions with the SE and shift manager,

that the oil sample had been scheduled for March 1998 based on the following

considerations:

• The pump cppeared to be operating properly.

• To limit tha number of pump motor start /stop cycles.

• To minimize the impact to the maintenance organization.

• A routina oil sample had been recently obtained (June 1997) and found to

be satisfactory.

The inspector later determined that the last reason was not valid because the

licensee was unable to provide documentation for the June 1997 oil analysis

results. The SE indicated that typically oil analysis results are not provided to

system engineering unless the sample results are abnormal. The SE indicated that

.he had not received an adverse report he assumed that the June 1997 oil analysis

resultc were satisfactory. The inspector was concerned that incorrect information

formed part of the basis for not promptly sampling the degraded oil, and also that

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the licensee was not aware that the June 1997 2B charging pump oil sample results

had not been obtained as scheduled by the lubricating oil analysis program.

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The licensee reviewed this information and elected to promptly sample the pump

motor oil. Tl.a sample results indicated that no motor bearing degradation existed

and attributed the foreign material to flaking of the epoxy coating applied to the

bearing housing. The licensee confirmed with the motor veMor that this condition

would not affect the motor operability. The SE increased the charging pump

sampling frequency to once per quarter from once per rsfueling outage to trend this

condition. The inspector concluded that the licensee's followup actions were

acceptable, however, he noted several weaknesses in the implementation of the oil

analysis program. This issue will remain unresolved pending further review of the j

oil analysis program (URI-50-443/97-08-05). f

c. Conclusions:

Several performance weaknesses were identified regarding the implementation of

the oil analysis program. Incorrect information was provided to the shift manager

which formed the basis for the decision to delay sampling the 2B charging pump

motor bearing oil. The motor oil was subsequently sampled and found not to

adversely affect the pump operability, and the oil sampling frequency was increased

to better monitor the pump motor oil condition.

E2.4 Pcsitive Displacement Charging Pump Oil Leak i

in Section E2.2 on page 22 of Inspection Report 97-07, the NRC identified an

unresolved item 97-07-01 involving an issue where the station did not promptly

correct an oil leak that challenged the relia'uility of the positive displacement

charging pump (PDP). The inspector noted that the licensee had not planned to

repair the leak until after installation of the modification which had actually been

canceled. This is an additional example of the corrective action system deficiencies

described earlier in this report. Appendix B Criterion XVI requires, in part, that

prompt corrective actions be taken for conditions adverse to quality. Contrary to

the above the licensee did not take prompt corrective actions for the PDP charging

pump oil leak. The other examples were noted in sections E1.1, E2.1, and E2.2

where corrective actions for degraded equipment conditions were not prompt or

effective. This is an apparent violation of 10 CFR 50 Appendix B Criterion XVI.

Unresolved item 97-07-011s closed and the issue will be reviewed, along with the

apparent violaticn (eel 50-443/97-08-02).

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E8 Miscellaneous Engineering issues

E8.1 (Closed) LER 50-443/97-018-00: Control Room Air Conditioning inoperability j

This LER discussed the inoperability of the CBA system compressors as discussed

in Section E2.2. The inspector independently reviewed this issue and concluded ,

that the'LER adequately described the event. This LER is closed, i

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E8.2 (Closed) LER 50-443/97-015-00:Potentially Non-Conservative Fuel Rod l

Performance Model i

This LER_was discussed in NRC Inspection Report 97-07, and involved a potentially ,

non-conservative fuel code performance model. The inspector performed an in-

office review of this LER and determined that it adequately described the issue and 1

no new concerns were identified. This LER is closed. I

E8.3 (Closed) LER 50-443/94-08-00.and 50-443/94-08-01:Non-Compliance With l

Technical Specification 3.8.4.2 Action Requirements

The inspector performed an in-office review of this LER which described a condition

involving non-safety related nuclear instrumentation drawers that were connected to  ;

a safety related power panel without a Class 1E protective device. Additionally, the

LERidentified the potentiallost of safety related power supply panels due to

interaction with non-qualifiad loads during a design basis seismic event. Technical l

Specification 3.8.4.2 requires an operable containment penetration conductor i

overcurrent protective device be connected between Class 1E power sources and i

non Class 1E circuits.1 bis event was identified by the licensee in April 1994 and

corrected prior to start-up from refueling outa0e three. This licensee identified, non-

repetitive, and corrected violation is being treated as a non-cited violation (NCV)  ;

consistent with Section Vll.b.1 of tha NRC Enforcement Policy. (NCV 50-443/97- )

08-04). {

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R1 Radiological Protection and Chemistry Controls

R1.1 General Comments

a. Insocction Scone

During the inspection period the inspector toured the radiologically controlled area

(RCA) on several occasions to observe radiological controls practices.

b. Observations and Findinos

The radiological controls technicianc at the RCA checkpoint and in tho field were I

attentive and provided hiqh quality assistance to ensure proper radiological work

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practices. All personnel observed were properly wearing dosimetry and protective

clothing as required, and were properly entering / exiting the RCA. The licensee

began to s eport the daily work group exposures at the station management meeting

to heighten personnel exposure awareness. This initiative was viewed as a positive

measure.

C. Conclusions I

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The radiological cetrols technicians at the RCA checkpoint and in the field were

attentive and provided high quality assistance to ensure proper radiological work l

practices. All personnel observed were properly wearing dosimetry and protective

clothing as required. The licensee began to roport the daily work group exposures

at the station management meeting to heighten personnel exposure awareness.

S1 Conduct of Security and Safeguards Activities

S1.1 General Comment (71707,71750)

The inspectors observed security force performance during inspection activities.

Protected crea access controls were found to be properly implemented during

random observations. Proper escort control of visitors was observed. Security

officers were alert and attentive to their duties.

P7 Quality Assurance in Security and Safeguards Activities

P7.1 Fitness For Duty Test Results

On Deceanber 8,1997, the licensee reported that a licensee supervisor tested

positive for alcohol when his test results were extrapolated back from the test time j

to the time he arrived on site. The licensee confirmed that the individual did not I

have vital area access during this period and initiated actions to address the

performance issue. The inspector concluded that the licensee's actions were

consistent with the fitness for duty program.

V. Manpoement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee

management, following the conclusion of the inspection period, on February 12,

1998. The licensee acknowledged the findings presented.

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

inspection should be considered proprietary. No proprietary information was

identified.

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X3 Other NRC Activities

On February 4,1998, the NRC presented its systematic assessment of licensee

performance (SALP) report for the period May 5,1996, through December 6,1997

at a public meeting held at the Seabrook Station.

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PARTIAL LIST OF PERSONS CONTACTED

W. Diprofio, Unit Director

G. Kline, Technical Support Manager

R. White, Design Engineering Manager

J. Peterson, Maintenance Manager

JJ. Grillo, Operations Manager

B. Seymour, Security Manager

J. Linville, Chemistry and Health Physics Manager

' G St Pierre, Operations Manager.

INSPECTION PROCEDURES USED

iP 37551: Onsite Engineering

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

Problems

IP 61726: Surveillance Observation

IP 62707: Maintenance Observation

'IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor -

Facilities

ITEMS OPENED, CLOSED, AND DISCUSSED

Ooened

Inspectors Followup ltem 97-08-01, Adequacy of Apparent Event Cause Evaluations

Escalated Enforcement item 97-08-02, Failure to Maintain the "A" SI Pump Operable

Escalated Enforcement item 97-08-03, Failure to Promptly Investigate Indications of RHR

Pipe Leakage

Escalated Enforcement item 97-08-04, Failura to Promptly Correct CBA System

Deficiencies

Escalated Enforcement item 97-03-06, Failure to Promptly Correct PDP Deficiencies

- Unresolved item 97 08-05, Lubricating Oil System Deficiencies

Non-Cited Violation 97 08-07, Non-Compliance With Technical Specification 3.8.4.2

Action Requirements

Closed

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Non-Cited Violation 97-08-07 and LER 94-08, Non-Compliance With Technical

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Specification 3.8.4.2 Action Requirements

Unresolved item 97-07-01, Adequacy of Corrective Action to Degraded Equipment-

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l. Conditions.

LER 50-443/97-018-00, Control Room Air Conditioning inoperability

LER 50-443/97-015-00,Potentially Non-Conservative Fuel Performance Model

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LIST OF ACRONYMS USED I

ACR Adverse Condition Report

ASME Anterican Society of Mechanical Engineers ,

CAS Central Alarm Station

CBS . Containment Building Spray i

EDG Emergency Diesel Generator  :

EFW Emergency Feedwater  !

FME Foreign Material Exclusion  !

gpd gallons per day l

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gpm gallons per minute

LCO Limiting Condition for Operation

MOV motor operated valve . g

MPCS Main Plant Computer System

NSARC Nuclear Safety and Audit Review Committee

NSARC OS NSARC Operations Subcommittee

psig pounds per square inch gauge

QC Quality Contro'

RHR Residual Heat Removal

SG steam generator

SIR Station information Report

SORC Station Operations Review Committee

SUFP Startup Feedwater Purnp

SW Service Water ,

TDEFW Turbine Driven Emergency Feedwater Pump

TS Technical Specifications

UFSAR Updated Final Safety Analysis Report

WR Work Request

CBA Containment Building Air Conditioning System <

p