ML20217F664

Insp Rept 50-219/98-80 on 980223-0313 & 0330-0402.Violations Noted.Major Areas Inspected:Engineering

ML20217F664
Person / Time
Site:	Oyster Creek
Issue date:	04/22/1998
From:	Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20217F631	List: ML20217F627 ML20217F649 ML20217F664
References
50-219-98-80, NUDOCS 9804280228
Download: ML20217F664 (28)

See also: IR 05000219/1998080

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No: 98-80  !

Docket No: 50-219

License No: DPR-16

Licensee: GPU Nuclear incorporated

1 Upper Pond Road

Parsippany, New Jersey 07054

Facility Name: Oyster Creek Nuclear Generating Station

Location: Forked River, New Jersey

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Inspection Periods: February 23,1998 - March 13,1998

March 30,1998- April 2,1998

Inspectors: Jimi Yerokun, DRS, Team Leader

Ram Bhatia, DRS

Carl Sisco, DRS

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Frank Arner, DRS

l Ron Eaton, NRR

Don Haverkamp, DRP

Tom Elsasser, Contractor i

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Approved By: Eugene M. Kelly, Chief,

Systems Engineering Branch

Division of Reactor Safety

9004280228 980422

PDR ADOCK 05000219

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EXECUTIVE SUMMARY

Oyster Creek Nuclear Generating Station

Report No. 98-80

A regional engineering team inspection was performed at Oyster Creek Nuclear Generating

Station (OCNGS) during the periods of February 23,1998 to March 13,1998, and March

30 to April 2,1998. The inspection consisted of Safety System Engineering Inspection

(SSEI); Safety Evaluation Program Inspection; and evaluation of the Effectiveness of

OCNGS at identifying, Resolving, and Preventing Problems.

In the systems area, the team selected the Automatic Depressurization System (ADS) and

the Containment Spray System (CSS). The CSS also included its heat sink, the Emergency

Service Water System (ESWS). The purpose of the inspection was to evaluate the

capability of the systems to perform safety functions required by their design bases, the

adherence to the design and licensing bases, and the consistency of the as-built

configuration with the updated final safety analysis report (UFSAR).

In the programmatic area, the team reviewed and assessed the processes in place for the

implementation of the requirements of 10 CFR 50.59 for proposed changes, tests and

experiments and the processes for implementation of the Corrective Action Program

including: Root Cause Analysis; Safety and Independent Oversight; Self Assessment; and

Operating Experience Feedback.

A significant concern was identified with the ADS system involving the DC voltage that

would be available to the EMRV solenoids during a small break loss of coolant accident

(SBLOCA) concurrent with a loss of offsite power and a failure of emergency diesel

generator #2. In this scenario, three of the five EMRVs would not have functioned as

required to depressurize the reactor because the voltage available to their solenoids would

not have been enough to operate the solenoids. This concern resulted in three apparent

violations as follows:

! * Failure to establish adequate design control measures to verify or check the

l adequacy of design voltage required for the ADS EMRV solenoid valves as required

by 10 CFR 50, Appendix B, criterion Ill, Design Control. (section E2.1)

• Failure to verify that the field installation of the EMRV solenoid voltage was

I representative of tb EQ documentation as required by 10 CFR 50.49,

Environmental Qualification. Further, when the NRC identified discrepancies with

the EQ program, GPUN was untimely at performing the program required

determination of operability. (section E2.1)

• Failure to maintain ADS operable as of March 19,1998, as required by Technical

Specification 3.4.B.1, ADS. (section E2.1)

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There were also some weaknesses with the methods established to ensure compliance

with some Technical Specification requirements associated with the ADS. While the ADS

functionality was not affected, an instance that resulted in a violation of Technical l

Specification was identified. The instance involved the failure, on October 6,1996, to

ensure that ADS was operable during the reactor pressure vessel test as required by

Technical Specification 3.4.B.1, ADS. (E2.1)

Apart from the issues discussed above, the ADS was maintained well. System

modifications were properly implemented. The discharge piping vacuum breakers were

adequately tested to the IST requirements and the acceptance criteria was consistent with

the design basis. Instrumentation and control design for the ADS and pressure relief

function was consistent with the design basis and licensing documents. l

The Containment Spray and Emergency Service Water Systems were maintained operable

and capable of performing their safety functions including during a loss of offsite power i

and a single active failure. Surveillance testing of system components were conducted in

accordance with existing procedures. The CSS and ESWS instruments were properly

calibrated and maintained. While initial conditions and the basis for some assumptions

were not always obvious, calculations and safety analysis adequately supported

implemented modifications. The team identified that some pertinent design information in

the UFSAR required updating. The licensee was aware of this and already had efforts

ongoing to update the UFSAR. However, witn regard to the resolution of seismic

deficiencies, there was untimely follow up and reporting to the NRC the status of SOUG

outliers. Also, two discrepancies that resulted in violations were identified as follows:

• Failure to adequately correct a seismic deficiency with a containment spray heat

exchanger as of February 26,1998, as required by 10 CFR 50, Appendix B,

Criterion XVI, Corrective Actions. (section E2.2)

• Failure to verify design calculations that supported the seismic adequacy of safety

related equipment as required by procedure EP-06 and 10 CFR 50, Appendix B,

Criterion V, instructions, Procedures, and Drawings. (section E2.2)

In the 10 CFR 50.59 program area, procedures were found to be comprehensive and

detailed in providing guidance and assigning responsibility for implementing the

requirements of 10 CFR 50.53 and updating the UFSAR. The procedures were also up to

date in incorporating revised industry and NRC 10 CFR 50.59 guidance and GPUN self

assessment findings.

10 CFR 50.59 Safety Evaluations (SEs) were of good quality and performed in accordance

with the requirements of 10 CFR 50.59 and the applicable procedures by qualified and

certified personnel. However, some SEs exhibited a lack of thoroughness and attention to

detail that was expected by the facility procedures. Two violations were identified as

follows:

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• Failure to submit the required changes, test, and experiments reports in 1983,

1986, and 1998 as required by 10 CFR 50.59(b) and 10 CFR 50.71(e). (section

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• Failure to comply with procedure EP-016 for Safety Evaluations on several

occasions as of February 26,1998, as required by 10 CFR 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings. (section E3.2)

Overall, the quality of the 10 CFR 50.59 training program for certification of RTR and ISR

was excellent. The contents of the training were appropriate and supported the OCNGS

review process that is being implemented. Safety evaluations were prepared and reviewed

by individuals who had received training regarding the preparation and review of SEs in

accordance with the facility procedure.

In the Correction Action Program area, Deviation Reports (DVR) reflected appropriate

operability determinations, and management attention necessary to identify causes and put

into place effective corrective actions. The Corrective Action training process was

acceptable and staff members were generally knowledgeable of the corrective action

process. The trending of DVRs was adequate and provided meaningfulinformation to

management. Although not all management expectations were met concerning the

program issues, industry operating experience was adequately used at the plant.

The assessments and evaluations of the Independent Safety Oversight Review Group, the

General Office Review Group, and Nuclear Safety Assessment staff were effective in

providing independent oversight of safety significant activities at OCNGS. The experience

of the Independent Safety Oversight members, both industry-wide and site-specific, was a

significant contributor to the value of their products. Management appeared to be full

supportive of the oversight groups and were responsive to their recommendations.

The corrective action and safety review audits were of high quality. Audit findings

received appropriate division management attention. The May 1997 safety review process

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assessment was self-critical and probing. The NSA audit and assessment reports were

effective in providing GPU Nuclear management independent identification of significant

findings and appropriate recommendations for process improvements.

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TABLE OF CONTENTS

PAGE

EX ECUTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

il l . Engi n e e ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

E2 Engineering Support of Facilities and Equipment ....................... 1

E2.1 Automatic Depressurization System . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

E2.2 Containment Spray and Emergency Service Water . . . . . . . . . . . . . . . . . 8

E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . 12

E3.1 10 CFR 50.59 Safety Evaluation Program . . . . . . . . . . . . . . . . . . . . . . 12

E3.2 Implementation of 10 CFR 50.59 Program .....................13

E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 16

E7.1 Problem Identification, Resolution, Prevention, and Corrective Actions . . 16

V. Management Meetings .........................................20

X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20  ;

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Reoort Details

Ill. Enaineerina .

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E2 Engineering Support of Facilities and Equipment

E2.1 Automatic Deoressurization System

a. Insoection Scope (IP 93809)

The team reviewe.d and assessed the operation, testing and mai' tenance of the

automatic depressurization system (ADS). The review included related sections of

the Updated Safety Analysis Report (UFSAR) and Technical Specifications (TS), the

System Design Basis Document, flow diagrams and other system drawings,

calculations, operating (normal and emergency) procedures, and in service and

surveillance test procedures and results.

The review was multi-disciplinary (mechanical, electrical and instrument & control)

and included a review of analysis that support system performance during normal

and accident conditions, walkdown of accessible portions of the system, and

discussions with cognizant system and design engineers. The review slso included: l

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verification of the appropriateness and correctness of design assumpicens;

confirmation that design bases were consistent with the licensing bar,3s; and

- verification of the adequacy of testing requirements.

b. Observations and Findinos

Mechanich_pesian l

The ADS consists of five electromatic relief valves (EMRVs), NR 108A, B, C, D, and

E, that actuate to rapidly reduce reactor coolant system pressure. There are two

discharge piping systems; one for valves A, B and E on the south header and one

for valves C and D on the north header. Two vacuum breakers are connected to

each EMRV discharge line. Their function is to prevent excessive water slugs in the

I discharge piping, which could lead to piping damage on a subsequent EMRV

actuation. Surveillance test 602.1.013, revision 4, ADS Downcomer Line Vacuum

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l Breaker Operability Test satisfied the requirements of the in-service Test Program

for the vacuum breakers. The acceptance criterion opening force of less than or

equal to 4.4 pounds was adequately supported by design calculations and test

methodology.

There are two modes of operation for the EMRVs. In the pressure actuation mode,

the EMRVs open when reactor pressure reaches the EMRV setpoint. In the

automatic depressurization mode, the valves open to depressurize the reactor vessel

when ADS logic channels sense high drywell pressure, low-low-low reactor water

level and a Core Spray booster pump running.

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The team reviewed a modification made to the system in 1994 that increased the

EMRV pressure relief function setpoints by 15 psig to 1085 psig and 1105 psig. l

The revised setpoints had been properly reflected in the EMRV pressure sensor test  ;

and calibration procedures. The procedure for operational guidance on the diagnosis

of EMRV system abnormalities and subsequent restorative actions also correctly

documented the changes. The calculations for the Core Spray Booster pump i

differential pressure switches were found to adequately support the existing

setpoints specified in the surveillance procedures and Standing Orders for

instrumentation setpoints.

The team reviewed surveillance test for the ADS and found that it adequately

verified EMRV operability. The team noted that System Engineering personnel were

cognizant of Information Notice 96-02. This Notice described an event where the

main disc of a power operated relief valve had not been repositioning during an

actuation signal. However the condition had been masked to the operators because

the acoustic monitoring system was identifying flow conditions. The team found

that the valve test at Oyster Creek provided operations personnel with alternate

methods of verification of main valve opening such as the requirement to trend

discharge piping temperatures. GPUN's surveillance test was found to have a valve

opening time acceptance criterion of 2.5 seconds. GPUN stated that this value was

consistent with paragraph 4.2.1.4(b) of OM-10, which required stroke times for all

power operated valves to be measured to at least the nearest second. However,

the team indicated that the 2.5 seconds criterion was technically unacceptable,

l since the ASME Code required a 2 second limit for rapid acting valves, and

therefore the intent of Position 6 of GL 89-04 was to establish a maximum struke

time limit of 2 seconds. After further review, GPUN initiated a procedure revision to

change the acceptance criterion to a maximum allowed value of 2 seconds. The

team reviewed the results of valve testing for the past 6 years and noted that in all

cases, the times were found to be below 2 seconds. Therefore, no significant

safety consequence was associated with this discrepancy.

TS 3.4.B.1 established the requirement for all five electromatic relief valves to be

operable whenever reactor water temperature is above 212*F and reactor pressure

is above 110 psig. The specification permits only the relief function of the EMRVs

to be bypassed during Reactor Vessel Pressure Tests. These conditions existed

during the reactor pressure vessel test performed during the period of October 5

through October 10,1996. TS Table 3.1.1, item G1 required high drywell

instruments to be operable to support ADS operability. TS 4.1.1, item 9 required

the high drywell pressure instruments to be channel checked ence per day. The

channel check is satisfied by documenting instrument log readings. However, the

required log readings were not performed during the October 1996 test. The team

noted that although the ADS function was required to be operable during the

pressure vessel tests, there existed no requirement to maintain primary containment

operable. Therefore the high drywell pressure permissive may not have been

achievab;e. Prior to the end of the inspection period, GPUN initiated a Technical

Specification Change Request (TSCR 255), to evaluate deleting the requirement for

ADS to be operable during vessel pressure testing. However, the failure to verify

ADS operability was contrary to the requirement of TS 3.4.B.1 and, therefore, a

violation of NRC requirements. (VIO 50-219/IIS-80-01)

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TS Table 3.1.1, permits the bypass of only one electromatic relief valve controller at

a time. The TS indicated that the amount of time that relief valve controllers may

be bypassed is limited to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> total for all controllers in any 30 day period. This

specification established limits on EMRV bypass configurations, to permit testing,

calibration and repair without significant loss of protection. When the team

questioned GPUN about how they ensured compliance with this requirement, they

did not have any established administrative controls to track the amount of time the

controllers had been historically bypassed. However, GPUN was able to provide

nominal times when the controllers were bypassed recently by a review of the

control room log book from January 1997 to January 1998. Procedure 602.3.004,

Electromatic Relief Valve Pressure Sensor Test and Calibration, had been performed

14 times with the test durations logged. The team concurred that based on the

provided documentation, compliance with the requirement had been demonstrated.

GPUN stated that procedure 602.3.004 would be revised to include controls

required to satisfy TS Table 3.1.1 requirements. Upon further investigation, GPUN

discovered that the T.S. limit should be eight hours and not three hours. it

appeared that during the processing of TS Amendment No. 75, a typographical error

had occurred and the number eight became cut off and appeared to be a three. The

team reviewed this information and concurred with the licensee's determination.

However, this was a weakness on the licensee's part at establishing formal controls

for assuring compliance with the requirements of the TS.

The team reviewed the UFSAR steam flow assumptions and noted that GPUN had

recognized inconsistencies in various sections of the UFSAR concerning EMRV flow

rates. Deviation Report (DVR) 97-01 had been previously initiated to address this

issue. Otherwise, the team found that ADS system design was consistent with the

UFSAR design basis requirements.

The team conducted a walkdown of the accessible areas of the ADS including the

panels and controls in the control room, and the EMRVs in the drywell, and

identified no discrepancy.

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Electrical Desian

The team reviewed the ADS logic, schematic and electrical drawings, and identified

no discrepancy. The team reviewed the available voltage at the terminal point of

the EMRV solenoid valves versus the acceptable minimum voltage required for the

valves to perform their intended design function and noted some discrepancies.

The licensee was unable to provide an appropriate calculation reflecting the voltage

at the terminal point of the valves nor test results to show the minimum voltage

required to operate the valves. As a result, GPUN issued a deviation report (DVR

98-0211)to evaluate the concern. The licensee then conducted a bench test on a

spare unit to determine the minimum voltage at which the EMRV pilot solenoid

valve could operate. The test was conducted at an ambient temperature of 69'F

under a simulated process condition. The EMRV pilot solenoid operated at a

minimum voltage of 70 volt dc. In addition, the licensee also performed a

preliminary voltage drop calculation that indicated that the minimum voltage at the

EMRV coil terminal points would be approximately 80 volts assuming an initial

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voltage of 116 Volts at the battery bus instead of the nominal 125 Vdc. Based on

this test result and calculation that showed that the available voltage would always

be more than the minimum required to operate, the licensee considered the EMRVs

operable at that Fme.

The team reviewed the licensee's analysis and noted that while the licensee had

assumed a conservative system voltage to calculate the available voltage (116 volts

instead of 119.4 volts that was obtained during the last end of the service test

performed in 1996 on B battery bank), there were still some discrepancies with their

l determination. For example, it was not clear that the ten conditions properly

simulated the expected plant conditions of the solenoids in an accident situation.

l Also, the assumptions and uncertainties used in the voltage drop calculations were

l not clear. The licensee indicated that their analysis and testing would further be

l confirmed by more testing at the solenoid vendor's laboratory.

The team reviewed the Environmental Qualification (EQ) of ADS components (EQ

file EQ-OC-301, Revision 2), and noted that the EMRVs solenoid valves were

qualified at a minimum voltage level of 105 volt de to perform their intended design

! function. This minimum voltage was, however, inconsistent with the licensee's

determination of 70 volts minimum voltage required and of the worst case 86 volts

available. The licensee indicated that their EQ documentation (Westec Report

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Project #6035 and GE PEP report # 42963) was very conservative. They stated that

the functionality of GE tests conducted as a part of the EQ tests (GE PEP report #

42963) included in their EQ documentation was overly conservative because of the

overconservative force assurned and that the recent test conducted indicating 65

Vdc (lowest) voltage was more representative of actual conditions for operation of

the EMRVs. Therefore, the EMRVs were determined to be operable with the

estimated 80 Vdc available at the terminal of the EMRV coil of the actuators. This

determination was documented in deviation report (DVR) 98-0250.

Upon further questioning by the team, the licensee reverted to equipment

qualification procedure, 5000-ADM-7317.01,(EP-031), Revision 7, Conduct of

Determination of Operability (DOO) to develop a justification for continued operation

(JCO) as required for all discoveries where EQ components or sub-components are

in nonconforming condition. The procedure required that a DOO must be developed

to document that the equipment in question was operable prior to discovery and to

justify continued operation until the planned corrective action can be implemented.

The licensee issued DOO-OC 119 on March 11,1998, and concluded that the

EMRV solenoids were qualifiable and would remain functional during accident

conditions and capable of performing their intended design function. To further

address the deficiency, the licensee developed a test plan for an EMRV/ solenoid .

operator and sent a spare valve to Wyle Laboratories for testing. However, the

team found that the licensee's EQ program implementation was weak, specifically in

validating the assumed critical parameters for their plant conditions in the

established EQ documentation. The team also identified a weakness with the

licensee staff not readily invoking the requirements of their established EQ program

procedure (EP-031) to justify the nonconformaning EQ component conditions until

further questioning by the team.

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Upon the completion of engineering analysis of the test results obtained from Wyle

testing, the licensee determined that the ADS would have not met its design basis

requirements. This was based on the fact that three of the five EMRVs would not

have functioned as required to depressurize the reactor during a small break loss of

coolant accident (SBLOCA) concurrent with a loss of offsite power and a single

failure of emergency diesel generator # 2. In that scenario, the three solenoid

valves (A, C and E) would have approximately 77.7; 73.7; and 74.2 volts de

respectively available at their terminals points. A minimum required voltage of 80

. volts had been established in the recent Wyle laboratory testing in harsh

environmental conditions. When this design deficiency was confirmed on

March 30,1998, the unit was already shutdown due to a condenser vacuum

problem which occurred on March 20,1998. This design deficiency was reported

to the NRC on March 30,1998, via a 10 CFR 50.72 (b) (2) (I) notification stating

that the ADS would not have met its design basis requirements. The licensee's

failure to establish adequate design control measures to verify or check the

adequacy of the required design voltage for the ADS solenoid which left the

solenoids with inadequate voltage until questioned by the NRC is an apparent

violation of 10 CFR 50, Appendix B, Design Control (eel 50-219/98-80-02).

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To address this concern, GPUN management assembled five teams to each

conduct root cause analysis; calculation ar.f testing; modification; extent of issues

review; and independent reviews. The licensee root cause analysis team

determined that this deficiency was attributed due to: (1) lack of engineering

process which did not force voltage analysis information into the EQ process; (2)

GPUN not treating voltage considerations as rigorously as other EQ parameters

(Radiation, heat, humidity); and (3) lack of clear ownership of determination that

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qualification criteria meet the installed configuration.

The GPUN modification team developed and implemented a modification that

involved adding cables and using spare conductors to reduce the circuit resistance

to improve voltage drop. A #4 cable was added between power panel DC-D and

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relay panel ER-18A to decrease the voltage drop in the EMRVs power supply circuit

to improve the available voltage at the terminals of the deficient solenoid valves.

Subsequent voltage drop calculations (C-1302-735-E320-037and 38 issued on

April 2,1998), considering the improved circuit resistances due to the above

modification, revealed that a worst-case minimum voltage of 84.6 Vdc would be

available at the terminal of EMRV "E" solenoid coil. Since the minimum

requirement, based on Wyle laboratory test, was 80 Vdc during the worst case

environmental conditions (281 degree F) and at 70 Vdc during normal operational

conditions (150 F), the NRC team determined that the licensee adequately resolved

the design basis deficient condition.

The team noted that the licensee's extent of issue team had also completed a

sample review of safety related AC and DC components for adequacy of voltage

drop calculations under their design basis conditions. The licensee stated that these

components were selected based on PRA consideration and that no significant or

similar concerns were identified. At the conclusion of this inspection, the GPUN

independent review team was reviewing all the licensee's team findings and

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recommendations to develop additionallong term corrective actions to address the

inadequacies. The GPUN EQ staff had revised the existing DOO to justify continued

operation based on the new test results, completed modification, and adequacy of

available voltage to all EMRVs solenoid valves.

The team found the weakness identified in the EQ program was significant because

it raised a question with the operability of the ADS valves.10 CFR 50.49(f)

requires each item of electrical equipment important to safety to be qualified.10

CFR 50.49(k) allows certain electrical equipment to be qualified in accordance wi9

" Guidelines for Evaluating Environmental Qualification of Class 1E Electrical

Equipment in Operating Reactors," November 1979 (DOR Guidelines). DOR

Guidelines, Section 5.2, Qualification by Type Testing, item 5, requires that

operational modes tested should be representative of the actual application

requirements (e.g. motor and electrical cable loading during the test should be

representative of actual operating conditions). In addition, item 6, requires that the

equipment qualification program should include an as-built inspection in the field to

verify that equipment was installed as it was tested.

Contrary to the above, from November 1984 through March 12,1998, the actual

application for the five ADS system electromatic relief solenoid valves in the

equipment qualification documentation (EQ-OC-301 dated 8/1/1989) was not

representative of the installed condition at Oyster Creek Station. The licensee also

did not perform analysis to validate the acceptability for the EQ established

qualification (a minimum of 105 Volt dc ) Specifically, the voltage requirement for

the EMRVs solenoid valves was not validated in the installed condition. This  :

absence of as-installed validation was contrary to the requirement of 10 CFR 50.49 l

and therefore, an apparent violation. (eel 50-219/98 80-03)

Also, as of March 19,1998, when the unit was in power operation mode, the ADS

was not operable as required by the TS because it was not capable of functioning

during a small break loss of coolant accident, concurrent with a loss of offsite

power and a worst case single failure. Specifically, TS 3.4.B.1, ADS, requires five

EMRVs to be operable when reactor water temperature is greater than 212 degrees

F, and pressurized above 110 psig. This is an apparent violation of TS 3.4.8.1.

(eel 50-219/98-80-04)

Updated Final Safety Analysis Reoort

Existing surveillance tests for the EMRV Acoustic Monitoring components and the

thermocouples adequately tested the functional capability of the system.

Preventive maintenance frequencies were conservative with respect to thermal

aging calculations found in the EQ files for the EMRV acoustic monitoring

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accelerometers and preamplifiers located in the primary containment. Section

! 7.6.1.1.8 (Relief Valve / Safety Valve Acoustical Monitoring System (VMS),

described an alarm on main control room panel 1F/2F which annunciates after a 2.2

second time delay to indicate that the valves have opened. The team found this to

be incorrect because, the system actually incorporates a 2.2 second time constant,

which is dependent on the magnitude of the signal. GPUN acknowledged this and

stated that they~ will clarify the UFSAR.

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c. Conclusion

A significant concern was identified with the ADS system involving the DC voltage

that would be available to the EMRV solenoids during a small break loss of coolant

accident (SBLOCA) concurrent with a loss of offsite power and a failure of

emergency diesel generator #2. In this scenario, three of the five EMRVs would not

have functioned as required to depressurize the reactor because the voltage

available to their solenoids would not have been enough to operate the solenoids.

This concern resulted in three apparent violations as follows:

• Failure to establish adequate design control measures to verify or check the

adequacy of design voltage required for the ADS EMRV solenoid valves as

required by 10 CFR 50, Appendix B, criterion ill, Design Control. (section E2.1)

e Failure to verify that the field installation of the EMRV solenoid voltage was

representative of the EQ documentation as required by 10 CFR 50.49,

Environmental Qualification. Further, when the NRC identified discrepancies

with the EQ program, GPUN was untimely at performing the program required

determination of operability. (section E2.1)

• Failure to maintain ADS operable as of March 19,1998, as required by

Technical Specification 3.4.B.1, ADS. (section E2.1)

There were also some weaknesses with the methods established to ensure

compliance with some Technical Specification requirements associated with the

ADS. While the ADS functionality was not affected, an instance that resulted in a

violation of Technical Specification was identified. The instance involved the

failure, on October 6,1996, to ensure that ADS was operable during the reactor

pressure vessel test as required by Technical Specification 3.4.B.1, ADS. (E2.1)

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Apart from the issues discussed above, the ADS was maintained well. System

modifications were properly implemented. The discharge piping vacuum breakers

were adequately tested to the IST requirements and the acceptance criteria was

consistent with the design basis, instrumentation and control design for the ADS

and pressure relief function was consistent with the design basis and licensing

documents.

I E2.2 Containment Sorav and Emeraency Service Water

a. Inspection Scope (IP 03809)

l The team reviewed and assessed the operation, testing and maintenance of the

Containment Spray / Emergency Service Water System (CSS /ESW). The review

included related sections of the UFSAR and Technical Specifications, the System

Design Basis Documents, flow diagrams and other system drawings, calculations,

operating (normal and emergency) procedures, and in service and surveillance test

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procedures and results.

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8 i

The review was multi-disciplinary (mechanical, electrical and instrument & control)

and included review of analysis that support system performance during normal and

accident conditions, walkdown of accessible portions of the system, and

discussions with cognizant system and design engineers. The review also included:

verification of the appropriateness and correctness of design assumptions;

confirmation that design bases were consistent with the licensing bases; and

verification of the adequacy of testing requirements.

b. Observations and Findinas

Mechanical and Electrical Desian

1

The team reviewed some calculations and safety analyses that support the CSS and

ESW system functions and found them generally thorough and accurate, although in

some instances, the reasons for selecting assumed values or initial conditions were

not always cbvious. In those instances, amplification by engineering department

personnel was necessary to fully understand the approach taken in analysis and

why the values used were correct and conservative. For example, the original

design flow assumed for analysis of the CSS was 3,000 gpm. Since initial

construction, system modification and procedural change have increased the actual

flow to rubstantially higher values. In the surveillance procedure, if CSS flow is

below~4,100 gpm, action is required to investigate and to increase system flow, in

various analysis of the CSS system, assumed flows ranged from 3,000 gpm to

4,100, gpm depending on the situation being analyzed. Generally, the reason for

the value assumed for analysis or calculation was not always fully developed. In

response to this, the licensee issued a deviation report regarding potential

inconsistencies between existing calculations that support the CSS and ESW

systems. DVR 98-0191, issued on February 25,1998, seeks to resolve the fact

that several active calculations covering the CSS and ESW systems have

discrepancies with each other and with the FSAR. These calculations were

reviewed by the licensee with applicability to correct design basis information and

found not to impact plant safety. The team independentlyi did not identify any

impact on plant safety either.

.

i

1

1

9

CSS and ESW system pump motors and applicable valves were found to be

appropriately powered from vital 460 volt motor control centers (MCCs) and

provided with backup power from their respective emergency diesel generators

(EDG). The team verified that associated motor load requirements and manual

starting sequence time were adequately reflected in the EDG loading calculation.

The team reviewed the system logic and identified no discrepancy. The team

verified that all the applicable system components associated with the CSS and

ESW pumps were consistent with the UFSAR requirements.

A significant modification was accomplished in 1993, that changed CSS from

automatic to manualinitiation. The team reviewed this modification and found that

it was properly analyzed, implemented and documented. The UFSAR, operating

procedures and emergency operating procedures were all revised appropriately to

reflect the changes in system operation. Instrumentation and controls were

provided to enable operators to manually initiate and trip the system as required.

As a follow up to seismic concerns addressed in NRC GL 87-02, Verification of

Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors,

and USl A-46, Seismic Evaluation Report, the licensee conducted system

walkdowns in 1994. During the walkdowns, the licensee identified a number of

seismic outliers associated with safe shutdown equipment including the

containment spray heat exchangers. In late March 1996, the licensee submitted to

the NRC, " Oyster Creek Nuclear Generating Station USl A-46 Seismic Evaluation

Report (Report #42112-R-001). This report (the summary report) was in response

to NRC Generic Letter 87-02 that encouraged utilities to participate in a generic

program to resolve the seismic verification issues associated with USl A-46. The

purpose of the report was to describe the results of the seismic reviews performed

to resolve USl A-46. The licensee's summary report indicated that the CSS heat

exchanger outlier had been resolved. However, the resolution of this outlier was

based on a preliminary licensee calculation which had not been design verified as

required by the licensee's procedure, EP-06. The initial calculation in the design

verification process to resolve this issue was completed in January 1997. From

January 1997 to February 1998, a number of administrative and technical issues

delayed the completion of the design verification process. A new analysis was

begun on February 2,1998 to resolve this issue, and is expected to be completed

by the end of June 1998. At the time of this inspection, the NRC had not been

notified of the change in the status of this outlier. As a result of the NRC Team

identifying this discrepancy, the licensee agreed to review the SOUG summary

j report to determine which other outliers have incomplete documentation and to

( revise the summary report accordingly. The failure to properly perform a design

verification of the CSS heat exchanger seismic calculation as required by Procedure

EP-06,is a violation of 10 CFR 50, Appendix B, Criterion V. (VIO S0-219/98-80-

05)

l

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10

l- System Walkdown

,

The team performed walkdowns of selected portions of the CSS and ESW systems.

'

Piping and mechanical components, piping interfaces with the service water system

and installation of instrumentation and electrical components were examined to

verify consistency with plant drawings. The team also examined the control room

instrumentation for monitoring CSS and ESW systems operation. The material

condition of the system and general housekeeping were good. Some discrepancies

that presented seismic concerns were noted involving: Chain hoists inadequately

stored on or in the vicinity of the CSS heat exchangers; and a neutron shield located

l

about one-inch from the CSS supply piping at the vicinity of drywell penetration

X66 for the CSS system.

i

!

Regarding the neutron shield, the licensee stated that it had been in place since

initial plant construction; however, the licensee was unable to identify any

documentation that describes the seismic adequacy of the shield. During the course

of the inspection, the licensee performed calculation SQ-OC-153-001 and concluded

l

that the shield support will not displace and that the containment spray piping and

! the support will remain intact during a postulated seismic event at Oyster Creek.

The team reviewed this analysis and identified no discrepancy, and accepted the

l resolution of the concern with the neutron shield. However, the team noted that

l the licensee's configuration control process was weak since the licensee had not

assessed the adequacy of the configuration until questioned by the team.

With respect to the chain hoist near the heat exchanger, the licensee stated that a

walkdown was scheduled to closeout the item, but had not been completed.

Shortly thereafter, a walkdown was completed by a structural engineer and it was

!

determined that the actions specified in Job Order 61509 were not adequate to

resolve the discrepancy. Further reviews by the team revealed that CSS walkdowns

,

conducted in August 1994 by the licensee utilizing SOUG methodology identified

! outlier conditions with respect to suspended chain hoists in the vicinity of the CSS

heat exchangers. This condition was documented in SOUG packages SQ-OC-H-21-

l 001 A and B, dated August 17,1994, wherein the outlier condition was described

l as " chain hoists in the vicinity of the heat exchangers need to be restrained due to

impact concerns." The proposed method of outlier resolution was to " modify chain

I

hoists or remove." in response to this condition, job order 61509 was issued on

i July 16,1996 and completed on December 6,1996; however, the corrective action

!

. was not verified as completed. Accordingly, on March 5,1998,the licensee then

l issued and completed another work request (776527)that corrected the improper

storage of the chain hoists.

l '

l- The team noted that seismic outliers continued to exist with respect to the

l containment spray system heat exchangers, storage of chain hoists on or around

the heat exchangers and the containment spray pumps. The initial work order

issued to correct the condition of the improperly stored chain hoists was not

adequate to correct the nonconforming condition. Further, the action to verify the

adequacy of the corrective action completed in December 1996 was not adequate.

This failure to implement prompt and adequate corrective action to resolve concerns

with seismic adequacy of safety related components is a violation of 10 CFR 50,

Appendix B, Criterion XVI. (VIO 50-219/98-80-06)

.

!

11

Updated Final Safety Analysis Reoort

The team reviewed the applicable FSAR sections for the CSS and ESW systems,

interf acing systems, and the associated electrical and instrumentation and controls

l sections, to verify consistency between the UFSAR, TS descriptions, and design

documentation. The following discrepancies were identified:

j * The UFSAR contained no discussions of the fact that 5% containment spray is

l diverted to torus spray during system activation, although this 5% diverted

l flow is taken into account during accident analysis and analytical calculations.

The licensee stated that a discussion of the 5% torus spray flow will be

l

included in a subsequent UFSAR revision.

• Section 1.2.2.2 of the UFSAR has not been updated to reflect the deletion of

the dynamic test mode from the containment spray system.

!

l * Table 6.2-7, " Containment Spray Heat Exchangers," has not been updated to

l reflect a 95*F tube side inlet temperature. The table footnote indicates that the

listed value of 85*F was derived from the vendor's heat exchanger

specification sheet; however, maximum inlet temperature has been revised

upward to 95*F.

The licensee indicated that they had a major effort ongoing to review and update

the UFSAR. None of these discrepancies presented an unreviewed safety question

and the team did not identify any immediate safety concerns with them, and was

satisfied with the licensee's ongoing efforts to resolve the issues.

c. Conclusion

The Containment Spray and Emergency Service Water Systems were maintained

operable and capable of performing their safety functions including during a loss of

offsite power and a single active failure. Surveillance testing of system cornponents

were conducted in accordance with existing procedures. The CSS and ESWS

instruments were properly calibrated and maintained. While initial conditions and

the basis for some assumptions were not always obvious, calculations and safety

analysis adequately supported implemented modifications. The team identified that

some pertinent design information in the UFSAR required updating. The licensee

was aware of this and already had efforts ongoing to update the UFSAR. However,

with regard to the resolution of seismic deficiencies, there was untimely follow up

and reporting to the NRC the status of SQUG outliers. Also, two discrepancies that

resulted in violations were identified as follows:

• Failure to adequately correct a seismic deficiency with a containment spray

heat exchanger as of February 26,1998, as required by 10 CFR 50, Appendix

B, Criterion XVI, Corrective Actions. (section E2.2)

)

.

l

12 l

e Failure to verify design calculations that supported the seismic adequacy of

safety related equipment as required by procedure EP-06 and 10 CFR 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings. (section

E2.2)

,

E3 Engineering Procedures and Documentation

!

E3.1 10 CFR 50.59 Safety Evaluation Proaram

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a. Insoection Scone (37001)

The team reviewed selected procedures and held discussions with GPUN

representatives to Mermine: (1) if proper procedural guidance has been

established for implementing the requirements of 10 CFR 50.59 for proposed

changes, tests and experiments (CTEs); and (2) if proper procedural guidance has

been established for updating the Final Safety Analysis Report (UFSAR), as required

by 10 CFR 50.71(e).

b. Observations and Findinas

The inspectors reviewed several corporate and division procedures which provide

guidance and responsibilities related to 10 CFR 50.59 and 10 CFR 50.71(e) J

requirements for OCNGS. The three administrative procedures defining the 10 CFR

'

50.59 program at OCNGS are corporate procedure,1000-ADM-1291.01, l

engineering division procedure,5000-ADM-1291.01(EP-016) and Oyster Creek  !

division procedure,130. Procedure 1000-ADM-1291.01 implements and controls

the GPU Nuclear Safety review and approval process and applies to all divisions of

GPU Nuclear. The procedure was up to date in incorporating revised industry and

NRC 10 CFR 50.59 guidance and GPUN self assessment findings. Procedure 5000-

ADM-1291-01 provides the Engineering Division basis and method for determining

whether a proposed change to TMI-1, TMI-2 or OC nuclear facility activities or

documents would adversely effect existing safety or environmental conditions,

including those governed by the site's Final Safety Analysis Report or Technical

Specifications. In addition, the procedure provides guidelines for complying with

10 CFR 50.59 and is used in evaluating acceptability of existing plant conditions.

Procedure 130 implements the GPU nuclear safety review and approval process for

the Oyster Creek Division and provides guidance for personnel involved in the

preparation and review of documents covered by the procedure. The procedures

contain appropriate requirements on the performance of 10 CFR 50.59 safety

reviews.

However, the team identified two weaknesses in the program as follows: In one

instance, most of the corporate procedure enhancements had not been reflected in

the Oyster Creek and Engineering Division 10 CFR 50.59 implementing procedure.

In the other instance, no GPU Nuclear corporate or division procedure provided

, guidance for formally reporting to the NRC the CTEs made in accordance with

Section 50.59 as required by 10 CFR 50.59(b)(2). The licensee indicated that

efforts were ongoing to improve the program. The team identified no other

significant discrepancy.

13

c. Conclusions

in the 10 CFR 50.59 program area, procedures were found to be comprehensive

and detailed in providing guidance and assigning responsibility for implementing the

requirements of 10 CFR 50.59 and updating the UFSAR. The procedures were also

up to date in incorporating revised industry and NRC 10 CFR 50.59 guidance and

GPUN self assessment findings.

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L

E3.2 Imolementation of 10 CFR 50.59 Proaram

a. Insoection Scope (37001)

The team reviewed some safety evaluations (SEs) performed by OCNGS in

accordance with 10 CFR 50.59 to determine if the SEs for plant permanent and

temporary modifications, and procedure changes addressed all safety issues

pertinent to the associated modifications or changes, and did not involve an

unreviewed safety question (USO).

b. Observation and Findinas

The team reviewed some Safety Evaluations involving the Automatic

Depressurization System, Core Spray, Emergency Service Water, and Containment-

Spray Systems. The team also reviewed selected CTEs for which the licensee had

determined that 50.59 safety evaluations were not required to verify that the

applicability determinations for these CTEs were made in conformance with the

50.59 procedures and controls. The team reviewed a sample of procedure changes

and determined that the evaluations were in accordance with OCNGS procedures in

that they reached the appropriate conclusions. Appropriate 50.59 applicability

determinations were made.

The team reviewed the training and qualification program for personnel involved

with the safety evaluation process to determine the quality of trainir.g and evaluate

the certification status of licensee's responsible technical reviewers (RTR) and

independent safety reviewers (ISR). Training and certification requirements have

been consistent with the commitments established in GPUN corporate plan 1000-

PLN-7200.01, GPU Nuclear Quality Assurance Plan. The inspector reviewed initial

and refresher training materials for some RTR and ISR and founce that they had been

trained in accordance with the program requirements to perform safety

determinations and safety evaluations. GPUN kept abreast of industry safety

evaluation guidance and participated in industry wide Nuclear Energy Institute (NEl)

licensing issues. Safety evaluations were prepared and reviewed by individuals who

had received training regarding the preparation and review of SEs in accordance

with the facility procedure.

. .

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14

The inspector noted in a few case that while the evaluations met the requirements

of the facility procedures, there were weakness in the thoroughness and

documentation by the preparer and/or reviewers. For example:

o Safety evaluation SE-402140-OO1, evaluated a modification to install additional

monitoring equipment, differential pressure gauges, in the Emergency Service

Water (ESW) System. The SE was completed on July 22,1983. During a

licensee assessment of the ESW system using NRC Temporary Instruction

2515/118, Rev 1, the licensee identified that the fittings used during the

modification did not meet the design pressure specifications for the ESC

system. As a result, the licensee issued a revision (Rev.1) to the SE justifying

the use of the fittings. The inspector pointed out some mistakes in the revised

SE regarding the design and maximum pressures of the fittings. As a result the

licensee issued a deviation report, DR 98-0210,to resolve the issue.

e Safety Evaluation SE OOO531-021, evaluated the replacement of the ESW keep

full throttle valves. The original SE was revised (Rev.1) in response to

deviationJeport, DO 97-1029,which recognized that the SE did not address

the possiole malfunction of a different type or possible reduction in a margin to

safety. This was licensee identified and corrected, however, the original

package contained a memorandum from Environmental Affairs identifying the

need for the Chemistry Department to review the proposed change to ensure

the discharge limit for total residual chlorine in the service water /ESW was not

exceeded. The licensee provided some meeting notes and e-mail that indicated

that some discussion of the chlorination flow took place, however, they did not

have an evaluation or calculation to ensure that they will not exceed the

applicable limit.

The team identified a discrepancy in the program implementation that, although

minor, was widespread. In several instances, the RTR and/or ISR did not make a

complete and appropriate Mtry in the signature block of the SE forms by printing

their name, in addition to signing their name, as required by Engineering Division

Procedure, EP-016, Nuclear Safety / Environmental Determination and Evaluation.

Interviews with some of the individuals conducting the reviews revealed that there

was not a consistent application of procedure (s) by the reviewer. This lack of

consistency in implementation of the procedure resulted in several instances of

failure to follow procedure. Procedure EP-016 prescribes the requirement for

implementing activities affecting quality as required by 10 CFR 50, Appendix B,

Criterion V, Instructions Procedures and Drawings. These instances of failure to

follow procedures represented another example of a violation of NRC requirement.

(VIO 50-219/98-80-05)

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15

10 CFR 50.59 Reoortina Reauirements

The team reviewed the facility submittals pursuant to 10 CFR 50.59(b) from

November 1982 to present. The licensee, in a letter dated November 5,1982,

submitted a report covering calendar years 1980 and 1981. In the report, the-

licensee acknowledged the untimeliness of the report and attributed it to the

transfer of reporting responsibilities from Jersey Central Power to GPU Nuclear

Corporation. No report was submitted in 1983 as required by 50.59(b) and the

" annual" report filed on March 1,1985, covere J calendar year 1983. There was no

report filed in 1986 as required by 10 CFR 50.59(b). The March 30,1987, report

covered calendar year 1984, and the reports filed on June 30,1987, and

October 30,1987, covered calendar years 1985 and 1986, respectively. Annual

reports were filed thereafter that covered the preceding year through 1993. The

annual report filed on February 16,1998, covered the period April 1993 to March

1995. This report did not meet the reporting requirements of 10 CFR 50.59(b). To

address all these discrepancies, the licensee plans to make an additional report this

summer to bring them current with the reporting requirements of 10 CFR 50.59(b)

and put them on a reporting schedule consistent with 10 CFR 50.71(e) as permitted

by 50.59(b). However, the repetitive nature of this issue as shown by the

licensee's failure to submit CTE reports for 1983 and 1986 and failure to submit

timely reports for 1993 through 1996, constitutes a more than minor f ailure to

adhere to the requirements of 10 CFR 50.59(b)(2). (VIO 50-219/98-80-07)

c. Conclusions

10 CFR 50.59 Safety Evaluations (SEs) were of good quality and performed in

accordance with the requirements of 10 CFR 50.59 and the applicable procedures

by qualified and certified personnel. However, some SEs exhibited a lack of

thoroughness and attention to detail that was expected by the f acility procedures.

Two violations were identified as follows:

e Failure to submit the required changes, test, and experiments reports in 1983,

1986, and 1998 as required by 10 CFR 50.59(b) and 10 CFR 50.71(e).

(section E3.2)

e Failure to comply with procedure EP-016 for Safety Evaluations on several

occasions as of February 26,1998, as required by 10 CFR 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings. (section E3.2)

Overall, the quality of the 10 CFR 50.59 training program for certification of RTR

and ISR was excellent. The contents of the training were appropriate and supported

the OCNGS review process that is being implemented. Safety evaluations were

prepared and reviewed by individuals who had received training regarding the

preparation and review of SEs in accordance with the facility procedure.

.. ..

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E7 Quality Assurance in Engineering Activities

>

' E7.1 Problem Identification, Resolution Prevention, and Corrective Actions

a. insoection Scoos (IP 40500)

The team evaluated the effectiveness of OCNGS controls in identifying, resolving,

and preventing issues that could affect the quality of plant operations or safety.

The controls included: corrective action programr; root cauae analysis programs;

independent onsite and offsite safety review grou,u; independent safety oversight; ,

self assessment activities; and the process that provides for the incorporation of

operating experience feedback.

b. Observations and Findinas

Corrective Action Proaram

)

Plant Procedure 104 " Control of Non-Conformance and Corrective Actions" Rev. 25

dated 11/17/97 provided the overall purpose and responsibilities of the deviation

report (DR) process. This process was to ensure events and situations which may

require further review, reporting, or corrective actions were identified, controlled, l

documented and evaluated. And also, to ensure that deviations which could affect

operability were identified and operability determinations made and documented.

The team reviewed the procedure and found that it adequately described the

deviation report process requirements.

The team reviewed, on a sampling basis, DVRs that had been generated during the

period January 1996 through early March 1998. Based on this review, the team

determined that appropriate operability determinations had been made. In addition,

each of the issues identified in the DVR had received an acceptable management i

review with respect to safety and the appropriate level of attention needed to I

identify causes and put into place effective corrective actions. In one instance,

when the team questioned the acceptability of the placement of electrical jumpers in  !

the reactor protection system (RPS) to bypass the scram function of the mode

switch in shutdown, the licensee prepared a DVR addressing the issue and promptly

- made a notification to the NRC in accordance with 10 CFR 50.72. The DR was

given the appropriate level of management review in accordance with the corrective

action program requirements. In addition, a plant review group (PRG) meeting was  ;

promptly scheduled to discuss this issue. Individual team members attended this

meeting and observed the licensee personnel discuss the issue in detail. The

licensee was able to determine that their practice was acceptable via a 1977 SER

(and TS Amendment) that had been approved by the NRC. However, this was not

properly reflected in the current technical specification. The licensee indicated that

the TS will be clarified to properly reflect the acceptability of the practice. The -

licensee properly followed their corrective action program requirements and

adequately evaluated, and documented this issue. The licensee subsequently

retracted the 10 CFR 50.72 notification.

.

.

17

The team determined; based on discussions with the training manager, that

corrective action training was conducted as part of general employee and licensed

operator training. Based on discussions with licensee staff, the team determined

the various staff members were generally knowledgeable of the corrective action

process.

Root Cause Analysis Prooram

The tea [n reviewed the process for ensuring that appropriate root cause

determinations are perfumed for identified problems. While the individuals making

root cause determinations were not required to be trained in root cause

determinations, all root cause determinations that were reviewed by the team

indicated that the determination were made correctly by trained personnel.' In

addition, based on discussions with licensee personnel, it was determined that there

was a management expectation that a person trained in root cause determinations

be on the team that makes such determinations.

Trendina of Deviation Reports

l

The status of DVRs are trended by the safety review group from a computerized

! data base. A periodic trending report is distributed to management. The team

l reviewed several of these reports and found they provided important and meaningful

information concerning the status of the corrective action program. Those DVRs

with extended required due dates are also tracked, and this information is

specifically provided to senior plant management. The safety review group also

provides a listing of all open DVRs to department heads on a routine basis. These

reports are discussed at the routine deWation report meetings and the routine

trending group meetings. The trending group conclusions are made part of the

routine trending reports. In addition, the system engineers are given a report of

each DR written on their system (s) and are requested to evaluate these DVRs and

advise the safety review group of any developing negative trends. The team

sampled several of the system engineer reports, including the associated DVRs, and

found the reports to be detailed.

The team reviewed the DR report status from January 1997 to January 1998. The

periodic trending report listed the number of DVRs that were issued and closed for

each month. As of January 1998, a total of 331 DVRs were still open. Of these,

50% were from the engineering department,12% from operations,14% from the

maintenance department,7% from the logistical support group and the other

stations groups accounted for 17% of the open DVRs. Also,84 of the open DVRs

were significant and had elapsed due dates. The team conducted a review on a

sampling basis of those DVRs and determined that adequate management attention

had been directed to track, trend and close them. No significant discrepancies were

identified.

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4

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Indeoendent Safetv Oversicht

There are three elements of oversight at OCNGS: (1) the independent Safety  !

Oversight Review Group (ISORG): (2) Nuclear Safety Assurance (NSA); and (3) l

General Office Review Board (GORB). The ISORG has no line responsibilities or line

functions, and is devoted solely to safety matters. It is independent of the plant

staff and reports offsite to the Director - Nuclear Safety Assessment. The Nuclear

Safety Assurance (NSA) audits, monitor and assess aspects of GPUN activities

within the scope of the GPUN Operating Quality Assurance Pisn or relating to

safety. This process provides for an overview of activities affecting or pctantia!!y

affecting safety. The GORB reports to and takes general direction from the GPUN

President, but has direct access to the Chairman of the Board and Board of

Directors. Its charter is broadly defined to encompass all matters potential affecting i

nuclear safety and radiation problems. NSA provides staff support to the GORB. l

l

The ISORG assessment topics were appropriately selected based on ongoing review l

and prioritization of site, industry and NRC safety concerns that could potentially

impact OC performance. The assessment reports clearly described the assessment

purpose and scope, the results of in-depth technical reviews of the selected topics,

and recommendations that were being tracked via the station action item tracking

system.

1

The inspectors reviewed the minutes of GORB meeting numbers 163 through 167,

which were conducted between February 1997 and February 1998. The meetings  ;

included appropriate briefings by GPUN directors and OC department manager of

the plant status and issues since the prior GORB meeting and detailed discussions l

of major activities and projects that were receiving senior management attention.

GORB reports contained detailed descriptions of the topics discussed and

recommendations resulting from GORB oversight reviews. The meetings included

appropriate discussions of diverse topics related to operations, maintenance,

engineering and plant support issues and concerns. )

i

The reports and activities were focused and appropriately critical. Both positive and

negative performance was emphasized for a balanced picture of OC strengths and

weaknesses. Issues that were identified by the ISO organizations were responded

to by plant management and evaluated for propor action depending upon the nature l

of the concern.

Self Assessment

The inspectors reviewed completed audits performed by the NSA department

addressing the corrective action program (Audits O-COM-96-03,0-COM-97-01, and

S-COM-97-07) and the safety review program (Audit S-OC-97-07). The audits were

performed at the proper frequency, and addressed performance as well as

compliance-related issues. The corrective action and safety review audits were of

good quality and the audits were properly implemented in accordance with

corporate policy 1000-PLN-72OO.1,GPU Nuclear Operational Quality Assurance

Plan, Rev.10, and adrninistrative procedure 1110-ADM 7218.01, Nuclear Safety

. . .- . . . .

.

.

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19

Assessment Audit Program, Rev. 2. The audits reviewed pertinent procedures,

records and departmental performance and included review of corrective actions

and management requested items. Significant findings were documented in

deviation reports for departmental response and corrective action development.

Audit findings received appropriate division management attention.

.The inspectors reviewed GPU Nuclear Assessment Report No. 6750-97-001,

OCNGS Safety Review Process implementation, May 1997. The report documented

1 special self-assessment conducted to review the effectiveness of the safety

review process with specific focus on the safety determination (SD) element of the

process at OCNGS, in response to SD inadequacies described in four recent NRC-

identified findings (unresolved item 96-07-04 and violations 96-09-02,96-11-01

and 96-12-01).

The initial procedure for implementing the self-assessment program, which became

effective on February 16,1998, provides detailed guidance and instructions and

appropriate responsibilities, based on extensive review of current industry and

consultant documents and input from other nuclear generating stations and

companies. The formal program implementation was determined to be too new to

assess the quality of self-assessments by line organizations.

Operatina Exoerience Review Prooram

Plant procedure 2OOO-ADM-12OO.02" Operating Experience Review Program" Rev 0

dated 3/20/95 provided the overall purpose and responsibilities for the operating

experience review program. This program was to establish a consistent method for

screening, evaluating and distributing industry and plant information to the

appropriate staff members. Also, pertinent information was to be tracked and

trended for management review and action as appropriate.

The team noted that a NSA audit had correctly identified that this program was not

implemented in such a manner that all managements expectations were met.

However, based on a review of records and interviews with personnel, the team

determined that the licensee actively participated in the sharing of pertinent

operating experience information using the nuclear network. Also, the operating

experience computer data base was used to enter both NRC and industry

organizations operating experience information and personnel interviewed were

aware of recent industry events. The team concluded that although not all

management expectations were met concerning the program issues, industry

operating experience was adequately used at the plant.

.

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20

c. Conclusions

in the Correction Action Program area, Deviation Reports (DVR) reflected

appropriate operability determinations, and management attention necessary to

identify causes and put into place effective corrective actions. The Corrective

' Action training process was acceptable and staff members were generally

knowledgeable of the corrective action process. The trending of DVRs was

adequate and provided meaningfulinformation to management. Although not all

management expectations were met concerning the program issues, industry

operating experience was adequately used at the plant.

The assessments and evaluations of the independent Safety Oversight Review

Group, the General Office Review Group, and Nuclear Safety Assessment staff were

effective in providing independent oversight of safety significant activities at

OCNGS. The experience of the Independent Safety Oversight members, both

industry-wide and site-specific, was a significant contributor to the value of their

products. Management appeared to be full supportive of the oversight groups and

were responsive to their recommendations.

The corrective action and safety review audits were of high quality. Audit findings

received appropriate division management attention. The May 1997 safety review

process assessment was self-critical and probing. The NSA audit and assessment

reports were effective in providing GPU Nuclear management independent ~

identification of significant findings and appropriate recommendations for process

improvements.

V. Mananoment Meetinas

X1 Exit Meeting Summary

On March 20,1998, the NRC held an exit meeting with members of GPUN at the Oyster

creek Nuclear Generating Station to discuss the findings of this inspection. The licensee

acknowledged the inspection findings. A list of those present at the exit is shown below.

Following additional inspection conducted between March 30 and April 2,1998, another

exit meeting was held via a telephone conference call on April 8,1998.

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PARTIAL LIST OF PERSONS CONTACTED

.

Licensee

• + G. Busch, Manager, Nuclear Safety & Licensing

M. Roche, Director, Oyster Creek

• + D. Slear, Director, Configuration Control

• + R. Tilton, Manager, Assessment

. P. Scallon, Manager, Safety Review

R. Baron, Safety Review Engineer

• + B. DeMerchant, Licensing Engineer

T. Corcoran, Plant Operations Engineer

K. Mulligan, Plant operations Director .

D. Croneberger, Director, Equipment Reliability

• + S. Schwartz, System Engineer

• J. Frank, System Engineer

• + D. Meisiero, Manager, Technical Support

• T. Wiggins, Media Relations

• + D. Kelly, Licensing

• + M. Godknecht, Engineering

• P. Burke, MTCE

• D. Robilland, NSA Lead Assessor

J. Logatto, Engineering '

• + S. Levin, Director, Operations & Maintenance

+ A. Agarwal, Manager, EP&l

+ D. McMillan

NRC

S. Pindale, Resident inspector

"J. Schoppy, Senior Resident inspector

• E. Kelly, Branch Chief, DRS

• W. Axelson, Deputy Regional Administrator

+ N. Perry, Project Engineer

Others

R. Pinney, Nuclear Engineer, New Jersey DEP

• Denotes those present at the March 20,1998 Exit Meeting.

.

+ Denotes those present on the April 8,1998 telephone conference call.

INSPECTION PROCEDURES USED

Procedure No. .Tji. tin

37001 10 CFR 50.59 Safety Evaluation Program

40500 Effectiveness of Licensee Controls in Identifying, Resolving, and

Preventing Problems

93809 Safety System Engineering Inspection

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ - _ _ _ _ _ _ _ . _ - _ _ _ _ _ _ _ _ _

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l ITEMS OPENED, CLOSED AND DISCUSSED

Ooened

Number Tvoe Descriotion

50-219/98-80-01 VIO Failure to verify ADS operability as required by TS 3.4.B.1. (Section E2.1)

1

50-219/98-80-02 eel Failure to ensure adequacy of the voltage for the EMRV l

solenoid as required by 10 CFR 50, Appendix B,

Criterion 111, Design Control. (section E2.1)

50-219/98-80-03 eel Failure to verify that the EMRV solenoid voltage was in

accordance with the EQ documentation as required by

10 CFR 50.49, EQ. (section E2.1)

50-219/98-80-04 eel Failure to maintain ADS operable as of March 19,1998,

l as required by Technical Specification 3.4.B.1, ADS.

l

50-219/98-03-05 VIO (1) Failure to perform a design verification of the CSS heat 1

exchanger required by EP-06 (10 CFR 50, Appendix B, l

Criterion V). (Section E2.2)

,

(2) Failure to follow procedure EP-016 as required by

10 CFR 50, Appendix B, Criterion V. (Section E3.2)

50-219/98-80-06 VIO Failure to implement adequate corrective actions for

l improperly stored chain hoist around a CSS heat

l

exchanger as required by 10 CFR 50, Appendix B,

Criterion XVI. (Section E2.2)

50-219/98-80-07 VIO Failure to submit CTE reports for 1983 and 1986 as

required by 10 CFR 50.59(b)(2). (Section E3.2)

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LIST OF ACRONYMS USED

ADS Automatic Depressurization System

CFR Code of Federal Regulations

CSS Containment Spray

CTE Changes, Tests and Experiments

DOO Determination of Operability

DRP Division of Reactor Projects

DRS Division of Reactor Safety

DVR Deviation Report

EDG Emergency Diesel Generator

EMRV Electromatic Relief Valve

EQ Environmental Qualification

ESW Emergency Service Water

GORB General Office Review board

GPUN General Public Utilities (GPU) Nuclear

l&C Instrumentation and Control

IP inspection Procedure

ISORG Independent Safety Oversight Review Group

ISR Independent Safety Reviewer

IST Integrated System Test

MCC Motor Control Center

NEl Nuclear Energy Institute

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

NSA Nuclear Safety Assessment

OCNGS Oyster Creek Nuclear Generating Station

PDR Public Document Room

PRG Plant Review Group

RPS Reactor Protection System

RTR Responsible Technical Reviewer

SE Safety Evaluations

SQUG Seismic Quality Utility Group

TSCR Technical Specification Change Request

UFSAR Updated Final Safety Analysis Report

USl Unresolved Safety issue

USQ Unresolved Safety Question

VMS Valve Acoustical Monitoring System

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