ML20045C426

Insp Rept 50-298/93-17 on 930329-0402 & 0503-07.Eight Examples of Apparent Violations Noted.Major Areas Inspected: Implementation of Deficiency Reporting,Operability Determination,Nonconformance Reporting & Maint Work Items

ML20045C426
Person / Time
Site:	Cooper
Issue date:	06/16/1993
From:	Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20045C414	List: ML20045C413 ML20045C426
References
50-298-93-17, NUDOCS 9306230096
Download: ML20045C426 (35)

See also: IR 05000298/1993017

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APPENDIX

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Inspection Report:

50-298/03-17

Operating License: DPR-46

Licensee: Nebraska Public Power District

P.O. Box 499

Columbus, Nebraska 68602-0499

Facility Name:

Cooper Nuclear Station

Inspection At:

Brownville, Nebraska

Inspection Conducted: March 29 through April 2, 1993

May 3 through 7, 1993

Inspectors:

E. Collins, Project Engineer

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P. Harrell, Chief, Technical Support Staff

W. Walker, Resident Inspector

J. Medoff, Chemical Engineer

F. Grubelich, Mechanical Engineer

Accompanyin Personnel:

C. Skinner, Intern

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Approved:

Ddte

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. R.ggliardo, Chief, Project Section C

Inspection Summary

Areas Inspected: Review of the licensee's implementation of the deficiency

reporting, operability determination, nonconformance reporting, and

operability evaluation processes through personnel interviews and by assessing

the effectiveness of corrective actions-for selected open and closed

nonconformance reports, deficiency reports, and maintenance work items.

Results:

Eight examples of an apparent violation, as listed below, were

identified for the licensee's failure to meet the requirements specified

in Criterion V of Appendix B to 10 CFR Part 50 for maintaining and

following safety-related procedures:

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Failure to implement a procedural requirement for performing an

adequate functional test on the hydrogen / oxygen analyzers because

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the operability of the heat tracing was not verified

(Section 4.2.4).

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Station procedures did not address the restoration of the elevated

release point radiation instrumentation after a loss of offsite

power (Section 11).

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Failure to implement a procedural requirement for verification of

the position of containment isolation valves prior to performing

the integrated leak rate test (Section 4.2.3).

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Overtime deviation requests were on file and not identified

(Section 12).

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Workers did not follow a maintenance work request (Section 12).

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Control room operators did not log the change in status of

critical plant components, such as primary and secondary

containment (Section 12).

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A station operator did not use or follow procedures when rackin'g-

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out an electrical breaker, resulting in a loss of shutdown cooling

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(Section 12).

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Two workers entered the drywell radiologically controlled area

without signing the special work permit (Section 12).

An apparent violation was identified for an inoperable secondary

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containment and inoperable hydrogen / oxygen analyzers during plant

operation, as required by Technical Specifications (Sections 4.1.3 and

4.2.2).

Five examples of an apparent violation, as listed below, were identified

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for the licensee's failure to comply with Criterion XVI of Appendix B to

10 CFR Part 50 for not identifying or promptly correcting conditions

adverse to quality or implementing actions to prevent recurrence for

significant conditions adverse to quality:

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The failure to resolve the issues identified with the failure of

secondary containment to pass the required leak rate test and to

address the missing loop seal in the piping that connects the

reactor building to the radwaste building (Section 4.1.2).

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The failure to take actions to prevent recurrence of setpoint

drift problems with the reactor coolant system relief valves

(Section 4.3).

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The failure to take actions to resolve the degradation of the fuel

oil that supplies the diesel generators (Section 5.1).

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The failure to promptly correct leaking shutdown cooling suction

isolation valves (Section 5.3.1).

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The failure to initially address the degraded conditions

identified with the paint on the interior of the emergency

condensate storage tanks (Section 6.1).

An apparent violation was identified for the failure to test the

internals of the hydrogen / oxygen analyzers to 58 psig, as required by

Technical Specifications (Section 4.2.3).

An apparent violation was identified for not complying with the

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requirements specified in 10 CFR Sections 50.55a(g)(1), -(4), and -(5)

for systems that are required to be included in the inservice

inspection (ISI) program (Section 7.3.4).

An apparent violation for inadequate justification for reverse direction

testing of containment isolation valves and nonconservative testing of

valves (Section 4.4).

Summary of Inspection Findinos:

Apparent Violations 298/9317-01 (Sections 4.1.2, 4.3, 5.1, 5.3.1, and

6.1), -02 (Sections 4.1.3 and 4.2.2), -03 (Section 4.2.3), -04

(Sections 4.2.3, 4.2.4, 11, and 12), -05 (Section 4.4), and -08

(Section 7.3.4) were opened.

Unresolved Items 298/9317-06 (Section 12), and -9 (Section 9) were

opened.

Inspection Followup Item 298/9317-07 (Section 6.1) was opened.

Deficiencies 298/93201-07, -10, -12, and -14 were closed (Section 12).

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Unresolved Items 298/9313-01, -02, and 298/93201-11 were closed

(Section 12).

Attachments:

Attachment 1 - Persons Contacted and Exit Meeting

Attachment 2 - List of Containment Isolation Valves

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DETAILS

1 PLANT STATUS

During this inspection, the plant was in a refueling outage, with the reactor

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core completely defueled.

2 INTRODUCTION

The first week of this inspection consisted of reviews and assessments of the

effectiveness of the licensee to identify and correct degraded and deficient

conditions. The reviews consisted of nonconformance reports, deficiency

reports, operability determinations, maintenance work requests, and personnel

interviews.

The second week of this inspection was conducted to review the licensee's

corrective actions to address the items that were identified in the first

inspection week and to verify that the licensee had adequately resolved or was

addressing the identified issues.

3 PERSONNEL INTERVIEWS (92720)

The inspectors interviewed individuals from the onsite organizations that were

involved with the implementation of the corrective action programs. The

interviews were conducted to establish each individual's understanding of the

corrective action programs and associated processes and to determine each

individual's personal experiences with the day-to-day use of the programs. As

a result of the interviews, the following items were identified:

Overall, it appeared that the deficiency reporting process had been well-

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accepted by the general plant population.

Some system engineers stated that implementation of the new deficiency

reporting process had an impact on their individual workload. The

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impact had resulted in less time being available for the individuals to

go into the plant and observe testing and maintenance on the equipment

in their assigned systems.

Individuals interviewed stated that they have had training on the

deficiency reporting process, but most. stated that the training was not

comprehensive.

For example, when asked by the inspector, most could not-

define what constituted a degraded or nonconforming condition.

In

addition, most individuals could not explain the circumstances of when a

deficiency report should be written.

Although management had not provided specific directions, some

individuals felt that they were not to write a deficiency or

nonconformance report unless absolutely necessary.

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In summary, individuals agreed that it would take time for the new process to

be implemented to the degree that is currently defined by the procedures and

that, with more practice in using the system, greater proficiency would be

obtained.

4 REiiEM OF NONCONFORMANCE AND DEFICIENCY REPORTS (92720)

The inspectors reviewed the licensee's procedures that implement the programs

for issuance and processing of deficiency and nonconformance reports. The

program details were provided in Procedures 0.5.1, "Nonconformance and

Corrective Action," and 0.5.2, " Deficiency Reporting."

In addition, the

inspectors reviewed selected nonconformance and deficiency reports and

evaluated the effectiveness of the licensee's corrective actions taken to

address the identified deficiencies.

During review of the programs defined in Procedures 0.5.1 and 0.5.2, the

inspectors did not note any concerns related to the program description.

During review of the implementation of the programs, problems were identified,

as discussed below.

4.1 Secondar_y Containment Testina

The inspectors reviewed the licensee's testing of secondary containment and

the effectiveness of the corrective actions taken for the deficiencies

identified during the testing. The review was performed to verify that the

testing of secondary containment had been appropriately performed by the

licensee.

4.1.1

Event Description

The plant was shutdown on March 5,1993, to begin the refueling outage. On

March 8, the licensee performed Surveillance Procedure 6.3.10.8, " Secondary

Containment Leak Test." This testing was performed by the licensee to

establish secondary containment integrity prior to offloading the reactor

core, as required by Technical Specification 3.7.C.

Prior to performance of

the test, the licensee performed preventive maintenance items on the reactor

building roof hatch, railroad airlock doors, reactor recirculation

motor-generator filter room doors, and reactor building exhaust fan room

doors. As documented in Surveillance Procedure 6.3.10.8, at Step 8.1.9, the

licensee was unable to establish 0.25 inches of water gauge (iwg) vacuum in

the reactor building and the test was terminated.

Licensee personnel stated

that the test results of March 8 were representative of the condition of the

secondary containment during plant operation.

From March 9-11, the licensee repaired seals on the outer railroad airlock,

inner railroad airlock, and reactor recirculation system motor-generator room

exhaust fan room doors. Additionally, the licensee refilled the reactor

building loop seals.

On March 10, the licensee attempted the test again, but

could not achieve 0.25 iwg vacuum in the reactor building. The results of

this test were not documented.

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On March 11, the licensee increased the vacuum in the radwaste building

from 0.1 to 0.2 iwg vacuum and was then able to obtain satisfactory results

from performance of Surveillance Procedure 6.3.10.8.

The secondary

containment was declared operable on March 11 and fuel movement began later

that day. On March 12, the licensee documented the surveillance test failure

of March 8 in Nonconformance Report 93-032.

Plant Engineering continued to review the performance of the secondary

containment and confirmed, on or before March 17, that a loop seal was missing

on a 10-inch pipe that connects the inside the reactor building to the

radwaste building. The missing loop seal created an in-leakage path from'the

radwaste building into the reactor building.

Increasing the vacuum in the

radwaste building, on March 11, reduced the differential pressure between the

reactor and radwaste buildings and apparently masked identification of the

missing loop seal.

Plant Engineering also raised a potential concern regarding the test

configuration of the secondary containment.

Performance of the test with

adjoining buildings (i.e., radwaste, turbine, and control) ventilation systems

at a negative pressure may have had an effect, either positive or negative, on

the ability of the standby gas treatment system to meet the acceptance

criteria of maintaining a 0.25 iwg vacuum in the reactor building. This

potential concern was documented in a memorandum, dated March 17, to the

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corporate office. The reactor core off load was completed late on March 17.

4.1.2 Problem Resolution and Use of the Licensee's Corrective Action System

The inspectors reviewed the licensee's initial ider.tification and resolution

of the problems identified during secondary containment testing. The

troubleshooting activities that were performed after the test tailure on

March 8 were informally implemented. The licensee performed testing of

airlock seals using the method of Surveillance Procedure 6.3.10.17, " Secondary

Containment Penetration Inspection," but did not formally implement this

procedure, did not document the results in a completed surveillance test, and'

did not document the degraded seals that were identified in the deficiency

reporting system.

Licensee personnel indicated that an informal performance

of the secondary containment integrity test was performed on March 10, which

failed, but the performance of the test and the results were not documented.

The surveillance test failure, on March 8, was not documented in a

nonconformance report until March 12.

Early on March 12, NRC inspectors asked

for a copy of the nonconformance report documenting the secondary containment

test failure, but one had not been written. Later that day, the licensee's

senior management directed that one be written. At the time of formal

documentation and assignment of corrective actions, the secondary containment

had already been declared operable and was being ' relied upon to perform its

intended safety function.

Procedure 0.26, " Surveillance Program," Revision 8,

Step 4.7.11.1, required that Technical Specification acceptance criteria or

Technical Specification violations shall always be identified as discrepancies

and a nonconformance report initiated per Procedure 0.5.1.

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Licensee personnel had increased the vacuum on the radwaste building prior to

obtaining satisfactory test results on March 11.

The licensee, however, did

not resolve this test configuration question prior to declaring the secondary

containment operable.

Licensee personnel appeared to have had previous

knowledge of how to manipulate adjacent building ventilation systems to obtain

acceptable test results. The effect of increasing radwaste building vacuum on

reactor building in-leakage masked the existence of the missing loop seal on a

10-inch pipe. The licensee was apparently motivated to complete the test

quickly to begin fuel offload and did not adequately resolve secondary

containment integrity deficiencies.

NRC Information Notice 90-002, " Potential Degradation of Secondary

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Containment," identified potential concerns regarding the effects of adjacent

building ventilation systems on the performance of secondary containment

integrity tests. The licensee's review of Information Notice 90-002 in 1990

did not identify the potential for the negative pressure in the radwaste

building to affect performance of the secondary containment integrity test.

The licensee's resolution of the secondary containment test failure on March 8

was ineffective in that the licensee did not identify the missing loop seal in

a 10-inch pipe running from the reactor building to the radwaste building.

The licensee's resolution of the missing loop seal and test configuration

concerns were ineffective since the licensee continued to move fuel and rely

on the secondary containment to perform its intended safety function without

correction of these deficiencies or an operability determination of the

deficiencies. The licensee stated, that since a loss of offsite power was not

assumed in the fuel handling accident, the reliance on adjoining building

ventilation systems was acceptable, even though they were not classified as

essential systems. Significant testing and evaluation was necessary to later

demonstrate that the secondary containment was operable on March 11.

Criterion XVI of Appendix B to 10 CFR Part 50 requires that measures shall be -

established to assure that conditions adverse to quality, such as failures,

malfunctions, deficiencies, deviation, defective material and equipment, and

nenconformances were promptly identified and corrected.

In the case of

significant conditions adverse to quality, the measures shall assure that the

cause of the condition is determined and corrective action taken to preclude

repetition. The licensee's failure to identify and correct the missing loop

seal after a secondary containment test failure on March 8 and prior to

declaring the secondary containment operable, and the licensee's failure to

resolve test configuration deficiencies prior to declaring the secondary

containment operable, is an apparent violation (298/9317-01).

4.1.3 Historic Secondary Containment Performance

The inspectors reviewed the past maintenance history, surveillance test

results, and nonconformance reports associated with the secondary containment.

Nonconfrnnce Report 3337 documented an invalid performance of the secondary

containn.ent integrity test in September 1984 and Nonconformance Report 6363

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documented the inability of the standby gas treatment system to maintain the

reactor building at 0.25 iwg vacuum in October 1986. The October 1986 failure

was attributed to degraded railroad airlock door seals and missing loop seals

in two reactor building floor drain lines.

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In response to Nonconformance Report 6363, the licensee formulated a

surveillance program to monitor known leakage sources on a periodic basis and

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to repair degraded seals, when necessary. Surveillance tests to inspect door

seals and loop seals were implemented in about 1988.

Since Nonconformance Report 6363, the licensee had experienced secondary

containment test Failures on May 20,1988; May 9,1989; April 26,1990; and

finally, March 8,1993. Nonconformance reports were not generated for the

1988, 1989, and 1990 failures, and consequently, no root causes were

identified and no corrective actions were taken to prevent recurrence. The

licensee's corrective action consisted of maintenance activities, mostly

associated with replacing the reactor building door seals.

Ineffective

licensee corrective actions led to inadequate maintenance of the secondary

containment, as indicated by the March 8,1993, test failure and the lack of

identification of a 10-inch missing loop seal and by the demonstrated

inability of the secondary containment to pass its integrity test in outages

without the performance of maintenance.

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Technical Specification 3.7.C requires secondary containment integrity during

all modes of plant operation, except when the reactor is subcritical, reactor

water temperature is below 212 F, no activity is being performed which can

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reduce the shutdown margin, no irradiated fuel is being handled, and no loads

which could potentially damage irradiated fuel are being moved. Without

secondary containment integrity, Technical Specification 3.7.C.I.e requires

that it be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least hot shutdown within the

next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee's maintenance and testing of the secondary

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containment were inadequate in that the standby gas treatment system was'not

capable of maintaining 0.25 iwg vacuum in the secondary containment, for an

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extended period, as indicated by the secondary containment test failure on

March 8, 1993. Operation of the plant, for an unknown period, with an

inoperable secondary containment until the plant was shut down on March 5,

1993, is an apparent violation of plant Technical Specifications

(298/9317-02).

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4.1.4

Licensee's Resolution of Secondary Containment Deficiencies

The licensee identified design deficiencies, maintenance inadequacies, and

ineffective corrective actions as the root causes for the secondary

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containment test failure on March 8, 1993. The licensee performed a secondary

containment integrity test on April 7 and estimated the, flow through the

10-inch missing loop seal. The licensee ' concluded, based on the standby gas

treatment system flow measured on March 11, plus the estimated flow through

the missing loop seal, that the secondary containment was actuall) operable on

March 11.

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The licensee revised Procedure 6.3.10.8.to establish the configuration of

adjacent building ventilation. systems.- The turbine.and control building

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ventilation systems were secured and the radwaste building ventilation system

was set at.0.05 iwg vacuum to minimize potentia 11 impact of the radwaste- .

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ventilation system on-the reactor building. On May 4, inspectors observed

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portions of the secondary containment integrity test.. The standby oas

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treatment system was maintaining 0.28 iwg vacuum with the fan flowrate at.

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about 1500 cfm. During these observations, the inspectors verified that~the

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loop seal had been installed.

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Additional licensee reviews identified that reactor building

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Door BLDG-000R-R301 was procured and installed as nonessential (i.e., not

safety related). The licensee also identified that several door seals were .

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procured as nonessential. The licensee subsequently dedicated the doors and

seals.

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The licensee also performed an independent review of issues related to

secondary containment. This review identified that no stroke timing of

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secondary containment isolation' valves was performed. The licensee

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subsequently implemented stroke time testing for the secondary containment

isolation valves to verify the stroke times referenced'in the Updated Safety

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Analy. sis Report.

At the end of this inspection, the licensee was reviewing the adequacy of.

operating cycle preventive maintenance activities that would be-implemented to

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maintain secondary containment. The licensee planned to-increase the

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frequency of door seal and loop seal surveillance tests. The licensee also

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planned, at the beginning of subsequent refueling outages, to perform an as-

found__ secondary containment integrity test.

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The inspectors concluded that the licensee's corrective actions, after the

first week of this inspection, were necessary to identify and correct reactor

building conditions adverse to quality.

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4.2 Hydrogen /0xygen- Analyzers

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The inspectors performed a review of the installation of the hydrogen / oxygen

analyzers to verify that the analyzers were installed properly and were

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functionally operational.

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4.2.1

Slope of the Lines from the DrYWell to the Analyzers

On October 5, 1989, Nonconformance Report 89-174 was issued to document that'

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the hydrogen / oxygen analyzers:had not been originally installed. in April

--1988, in accordance with the installation requirements. The rmonformance

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report noted that the' slope of;the sample. lines from the drywrd1 to the

analyzer cabinets was not adequate. The improper slope of the lines caused

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'.the. analyzers to be unreliable because the low sections. collected condensate,

which resulted in low flow conditions 'and subsequent' shut down of the ~.

analyzers. To address the problem with the slope of the lines, the licensee

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initiated Design Change 89-207.

This design change was installed in April

1990, which was the first refueling outage following the initiation of the

nonconformance report, in an attempt to resolve the line slope problems.

After implementation of the design change, a subsequent review indicated that

line slope problems still existed. These line slope problems were eventually

addressed during the current refueling outage.

4.2.2

Installation of Particulate Filters in the Sample Lines

After hydrogen / oxygen analyzer installation, the licensee also experienced

problems with failure of the analyzer sample pumps.

The licensee's

investigation, as to the cause of the pump failures, indicated that

particulate matter was entering the pumps from an unknown source. To address

the pump failure problems, the licensee installed, as directed by Des 1gn

Change 89-207, particulate filters in the suction lines of the sample pumps.

Approximately 1 month after installation of the filters, the licensee began

experiencing problems with the analyzer indication in the control room.

The

licensee's evaluation of the erratic indication identified that the newly

installed filters were a condensate trap, caused when the high humidity and

high temperature air from the drywell entered the filter and condensed. The

presence of the condensate caused the hydrogen / oxygen detector to display

erratic readings in the control room.

To address this problem, the licensee opted to issue periodic maintenance work

requests to remove the filter from service, disassembla it, dump the

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condensate from the filter bowl, and return it tc :;ervice. The licensee had

been performing this evolution about once or twice a week, from 1990 until the

current refueling outage, when the filters were removed from the system.

Based on the licensee's need to routinely remove the condensate from the

filters, the inspectors were concerned with the reliability of the analyzers

to perform their intended design function during a design basis,

loss-of-coolant accident (LOCA) since the analyzer indications in the control

room were erratic and considering the fact that the licensee could not access

the filters to remove'the condensate during a LOCA, since the filters were

located in the reactor building. The licensee stated that an evaluation would

be performed, prior to startup from the current outage, to assess the

reliability and capability of the analyzers to perform their intended accident

function. The licensee removed the filters from the analyzer sample lines

during the current refueling outage.

Investigation of the failure of the

pumps by the licensee indicated that the failures were not due to particulate

matter entering the pumps from an outside source. The licensee determined

that the source of particulates was from within the pumps themselves and had

opted to replace the pumps with a newer design.

It should be noted that the

design change for removal of the filters and correction of the slope of the

sample lines was originally scheduled to be completed during the 1991 outage;

however, due to manpower and financial considerations, the task was delayed

until the current outage.

The above discussion was an example of how the licensee had opted to live with

a problem (i.e., removing the condensate from the filters) rather than being

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proactive and taking the appropriate actions to resolve a degraded or

nonconforming condition. Also, no operability determination of the

deficiencies was performed.

Technical Specification 3.2.4 and Table 3.2.4 state that primary containment

hydrogen concentration analyzers PC-AN-H,/0,I and -H,/0,II are required to be

operable at all-times, except when the reactor is in cold shutdown or in the

refuel mode during a refueling outage. The licensee operated the facility in

modes other than cold shutdown or refueling, from April 1990 to March 5,1993,

with particulate filters installed in hydrogen concentration analyzers

PC-AN-H,/0,1 and -H,/0,II, which rendered the analyzer inoperable. This is the

second example of an apparent violation of plant Technical Specifications

(298/9317-02).

4.2.3 Leak Rate Testing of the Analyzers

During review of the modification of ?.he analyzers during the current outage,

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the inspectors noted that the licenser's instructions failed to provide an

appropriate test of the sample lines, from the containment isolation valves to

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the cabinet, and of the internals of 1he cabinet. The initial instructions

provided in the modification package cirected that the piping from the

containment isolation valves to the cabinet be tested to 40 psig and the

internals of the cabinet be tested to 5-10 psig.

Based on a concern

identified by the inspectors during the first week of this inspection with

respect to penetration testing, the licensee identified that the

postmodification testing instructions were not appropriate in that the sample

piping and cabinet internals were not tested to the requirements specified in

the Technical Specifications. Since the piping to the analyzer cabinets and

the internals of the cabinet constitute a primary containment pressure

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boundary during a design basis event, the Technical Specifications require

that the test pressure be 58 psig. The licensee revised the testing

instructions provided in the modification package to require that the piping-

and cabinet internals be tested to the value specified in the Technical

Specifications. The licensee stated that the testing would be completed prior

to startup from the current refueling outage.

During further review of the testing that had been performed on the cabinet

internals, the inspectors established that the licensee had never tested the

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cabinet to the 58 psig requirement specified in Technical Specification 4.7.A.2.

The failure to test a primary containment pressure

boundary to the specified value is an apparent violation (298/9317-03).

In response to this problem, the licensee committed to a review of-cabinets,

whose internals serve as a primary containment pressure boundary, would be

performed, prior to plant startup from the current refueling outage, to verify

that the internals of the cabinets have been tested to the appropriate

pressure level.

The inspectors also reviewed the testing that the licensee had performed on

the piping that connects the primary containment to the analyzer cabinet. The

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review performed by the inspector identified that the piping was most likely

tested, as required, during the performance of the integrated leak rate test;

however, this could not be positively established since the procedure used by

the licensee was not specific as to the required valve lineup that was to be

used for the testing. The licensee did not verify the actual position of the

containment isolation valves for the analyzers prior to performing the

integrated leak rate test, since the valves were normally open and the

licensee had no reason to believe that the valves may have been shut.

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basis for the licensee's statement was that the general approach used to

verify valve positions was for the operations department to perform a review

of tagouts prior to performance of the test to ensure that all penetration

isolation valves, required to be open, were not tagged shut. This approach

was based on the assumption that the containment penetration valves were in

the position that they would be expected to be in during normal plant

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operation.

10 CFR Part 50, Appendix B, Criterion V, states that activities affecting

quality shall be prescribed by documented instructions, procedures, or

drawings, of a type appropriate to the circumstances and shall be accomplished

in accordance with these instructions, procedures, or drawings.

Instructions,

procedures, or drawings shall include appropriate quantitative acceptance

criteria for determining that important activities have been satisfactorily

accomplished.

The failure to implement a procedure for integrated leak rate testing that

specifies the position of valves, which are required to be in a specific

position, and to require verification of the specified position is an example

of an apparent violation of CriteMn V (298/9317-04).

4.2.4 Operability of the Heat Tracina Within the Analyzer Cabinets

The analyzer cabinets contain heat tracing on the inlet piping to the

hydrogen / oxygen detection chamber. The heat tracing was designed to heat the

air / vapor mixture entering the detection chamber to ensure that excessive

moisture did not enter the detector. The temperature of the heat tracing

operates as a function of drywell pressure. As the pressure increases, the

heat tracing temperature also increases.

Excessive moisture will cause the

detector readings to be erratic; therefore, the heat tracing must be operable

for the analyzers to be considered to be operable.

The inspectors noted that no routine verification was performed to verify that

the heat tracing was functioning. The licensee stated that a functional test

was performed monthly, but the monthly test did not verify the operability of

the heat tracing. The licensee also stated that the analyzers very seldom

pass the monthly functional test and, as required by the functional test

procedure, a calibration test was performed.

The calibration test did verify

the operability of the heat tracing inside the cabinet.

Because the

calibration test was routinely performed, the licensee stated the.t assurance

was provided that the heat tracing remained operable.

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10 CFR Part 50, appendix B, Criterion V, states that activities affecting

quality shall be prescribed by documented instructions, procedures, or

drawings, of a type appropriate to the circumstances and shall be accomplished

in accordance with these instructions, procedures,'or drawings.

Instructions,

procedures, or drawings shall include appropriate quantitative acceptance

criteria for determining that important activities have been satisfactorily

accomplished.

Table 4.2.H of the Technical Specifications require that a functional test be

performed to verify the operability of the analyzers; however, the procedure

used to perform this did not verify the operability of the heat tracing. This

is an example of instructions or procedures that were not appropriate and is

an example of an apparent violation of Criterion V (298/9317-04).

The inspectors observed that there was no remote indication for operations

personnel that the heat tracing remains functional.

In response, the licensee

planned to place an existing temperature alarm in service. When the

temperature of the heat tracing falls below a preset value, it will provide a

local alarm and also an alarm in the control room. The licensee committed to

return the temperature alarm to service prior to the end of the current

refueling outage.

4.3 Pressure Isolation Valve Setpoint Drift

The inspectors reviewed Nonconformance Report 93-067, which documented safety

relief valve drift above Technical Specification limits. Seven of eight

valves had drifted +6.1, +2.1, +5.0, +10.2, +15.0, .+2.3,

and +3.5 percentages

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from t .e nominal setpoint. Technical Specifications allow a +3.0 percent

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tolerance for relief valve setpoint drift.

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At the time of this inspection, the licensee had not completed the root cause

analysis for Nonconformance Report 93-067, but the-licensee attributed the

drift to corrosion bonding of the pilot valve poppet to its seat. The

licensee's corrective actions were to refurbish the pilot valves,: reset the

valve, and reinstall the valves. The licensee was also following industry

efforts to resolve this problem.

The inspectors reviewed the relief valve as-found lift setpoints from the

three previous outages.

In 1989, three valves drifted high, with none above

3 percent; in 1990, three drifted high, with one valve above 3 percent; in

1991, eight valves drifted high, with three above 3 percent; and in 1993,

seven valves drifted high, with five above 3 percent. The average drift of

valves that exceeded the tolerance increased from 0.7 percent in 1989 to

6.3 percent in 1993. These as-found lift setpoints indicated a trend of

increasing valve drift tendencies.

The inspectors reviewed the licensee's root cause determination for

Nonconformance Report 91-103, which documented the 1991 outage as-found-

setpoint values.

The licensee identified the root cause to be vendor design

and that the valves generally displayed performance characteristics typical of

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corrosion bonding of the pilot disc and labyrinth seal friction-induced

setpoint drift.

Licensee corrective actions were to refurbish and reset the

valves and to submit a Technical Specification change request to increase the

allowed drift tolerance to i3 percent.

An analysis performed by the reactor vendor concluded that the integrity of

the plant was not affected by the as-found conditions. The analysis assumed

that one valve would lift at 1250 psig and the remaining valves would lift at

1210 psig (+10 percent of the nominal setpoint). The peak pressure for this

analysis was 1310 psig.

The Updated Safety Analysis Report evaluation for

this transient indicates a peak pressure of 1245 psig.

The licensee concluded that the setpoint deficiency was an industry problem

and that no further corrective action was planned until the industry problem

was resolved. The inspectors noted that even with the proposed Technical

Specification change, five of eight valves would have been out of tolerance.

The inspectors did not find any corrective action to prevent recurrence for

relief valve setpoint drift or to mitigate this condition.

The inspectors asked if this condition represented an unreviewed safety

question, but the licensee had not performed a 10 CFR Section 50.59 for plant

operation with this condition. The inspectors concluded that relief valve

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setpoint drift above the Technical Specification limits was a potential

unreviewed safety question.

Relief valve drift above the Technical Specification limits was a significant

condition adverse to quality and the licensee had not established measures to.

mitigate this condition or prevent recurrence. This is another example of an

apparent violation of Criterion XVI (298/9317-01).

4.4 Reverse Direction Testina of Containment Isolation Valves

Nonconformance Report 93-075 documented the local leak rate test failure of

Valve RHR-M0-18.

The valve passed when the test was performed with pressure

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applied in a direction opposite to accident pressure (the licensee's

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practice), but failed when the test pressure was applied in the direction of

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accident pressure. Appendix J to 10 CFR Part 50 allows reverse direction

testing of containment isolation valves if the testing is equivalent or

conservative.

The inspectors questioned the licensee regarding the validity of reverse

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direction testing when the test results on Valve RHR-M0-18 indicated that the

testing was nonconservative. The licensee indicated that reverse direction

testing would have to be reviewed. At the time, the licensee had not

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documented the Appendix J testing inadequacies in a corrective action system.

Nonconformance Report 93-075 actions were changed to include this review prior

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to the end of the first week of this inspection.

Repair activities for

Valves RHR-M0-18 and -17 are discussed in Section 5.3 of this report.

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The inspectors reviewed the licensee's existing justification'for reverse

direction testing of flex-wedge, double-disc gate valves. The licensee had

information from the vendor that indicated that the test pressure of 58 psig

was not enough to unseat the upstream disc. Thus, the vendor concluded that

the direction of the test pressure would not normally affect the test results.

After the failure of Valve RHR M0-18, licensee review-iden61fied that a total

of 26 containment isolation valves were tested in the reverse direction

without an adequate basis that the testing was equivalent or conservative.

See Attachment 2 for the specific valves.

For those valves where the configuration would allow testing with pressure

applied in the accident direction, the licensee planned to test the valves.

For those valves where the configuration would not allow testing with pressure

applied in the accident direction, the licensee planned to develop

justification or submit an exemption request to the NRC. At the end of this

inspection, the licensee was developing this justification.

10 CFR Part 50, Appendix J,Section III.C, states for valve local leak rate

tests that the test pressure shall be applied in the same direction as that

applied when the valve would be required to perform its safety function,

unless it can be determined that the results from the tests for a pressure

applied in a different direction will provide equivalent or more conservative

results.

Reverse direction testing of containment isolation valves without

determining that results were equivalent or conservative is an apparent

violation (298/9317-05).

5 REVIEW OF OPERABILITY DETERMINATIONS AND EVALUATIONS (92720)

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The licensee had established a program to evaluate equipment operability when

a degraded or nonconforming condition was identified. The licensee's program-

had been implemented by the issuance of Precedures 0.27, " Operability of

Systems, Structures, and Components," and 0.27.1, " Operability Evaluations."

The inspectors reviewed the program, as specified in the implementing

procedures, to verify that the licensee had included the appropriate elements

in the operability evaluation program. No problems were noted with the

documented program.

In addition, a review was performed to verify that the

licensee was appropriately implementing the established requirements for

determining equipment operability. During this review, it was noted that the

licensee's equipment operability determinations were generally adequate;

however, problems were identified with the licensee's performance in this

area. The areas of concern are discussed below.

5.1 Review of the Operability Determination on the Quality of the Fuel Oil

Supply for the Emergency Diesel Generators

On July 18, 1991, the NRC issued Information Notice 91-46, " Degradation of

Emergency Diesel Generator Fuel Oil Delivery Systems," to inform licensees of

problems that occurred at seven nuclear facilities because of degraded fuel

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oil supplies. The information notice discussed several instances where diesel

generators had failed to perform their intended safety function because the

filters and/or strainers in the fuel oil delivery system had clogged because

of high particulates in the fuel oil tanks. To address the problems that were

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identified in the information notice, the licensee issued Revision 13 to

Procedure 6.3.12.3, " Diesel Fuel Oil Quality Test," to include a requirement

to test the diesel generator fuel oil tanks for particulate contamination.

The licensee established an administrative particulate limit of 10 mg/1, which

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was the limit referenced in Information Notice 91-46. The Technical

Specifications did not require that the fuel oil be sampled for particulates.

On November 16, 1992, the licensee performed the first sampling, after

Revision 13 to Procedure 6.3.12.3 was issued, of the diesel generator fuel oil

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tanks for particulate contamination and found that the particulate limit of

10 mg/l was exceeded in both tanks. The as-found values were 15.2 mg/l for

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Tank A and 13.4 mg/l for Tank B.

To address this out-of-specification

condition. the licensee initiated Operability Determination 92-074 on

November 20. The disposition of the operability determination stated that

exceeding the limit was not an operability concern because the fuel oil

delivery system contained filters and strainers that would be able to remove

particulate matter from the fuel oil and, thercfore, the particulate matter

would not be able to enter the engine. The licensee's operability

determination also stated that a visual inspection of the fuel oil had been

performed and no particulate could be seen and that the manufacturer of the

engine had no specific requirements for contamination of the fuel. As a

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result of the operability evaluation, the licensee determined that the diesel

generators continued to be operable. The Station Operations Review Committee

reviewed the determination made by the licensee's engineering staff and agreed

that the diesel generators remained operable.

During a review by the inspectors, it was noted that the evaluation performed

Dy the licensee did not address the concerns discussed in Information Notice 91-46.

In the information notice, the concerns identified with other

facilities involved the plugging of the filters and/or strainers in the fuel

oil delivery system and did not discuss the affect of the particulate matter

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entering the engine. The operability determination performed by the licensee

only focused on the potential effects of the particulates on engine

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performance and did not address the potential for clogging of filters and/or

strainers.

The licensee's approach to resolution of the degraded condition

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was weak in that the licensee established an administrative limit for

particulates and, when the first sample was taken that indicated the limit was

exceeded, an evaluation was performed that disregarded the limit. The

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licensee did not implement or plan action to correct the high particulate

concentrations.

For this reason, it was apparent that the approach taken to

resolve this potential safety concern was not conservative and only addressed

the items that would provide a basis for continued operation-of the diesel

generators and of the facility.

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On January 27, 1993, the licensee sa , led the fuel oil tanks and identified

that the particulate level for Tank A was 11.6 mg/1.

In this case, the

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licensee did not perform an operability evaluation of the degraded condition.

During interviews with licensee personnel, the inspectors established that the

reason that an evaluation was not performed was'that the previous operability

determination encompassed the subsequent out-of-specification indication

(i.e., since the last reading was not a concern and it was higher than this

reading, the current particulate contamination level was acceptable).

Since the operability determination performed by the licensee concluded that

the diesels were operable, as discussed above, no corrective action was taken

or planned to reduce the particulate contamination level in the fuel oil

tanks, even though the degradation was apparent. The failure to implement

corrective actions for a degraded or nonconforming condition is another

example of an apparent violation of Criterion XVI (298/9317-01).

To address this issue, the licensee, as a result of concerns identified by the

NRC, took actions to reduce the particulate contamination in the diesel fuel

oil tanks.

The licensee filtered the fuel oil in Storage Tanks A and B and

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the day tank for each diesel generator to reduce the particulate level to less

than 2 mg/1. The licensee verified the results of the filtering efforts by

sampling the four tanks.

In addition, to address the potential for future

degradation of the fuel oil, the licensee had submitted a Technical

Specification amendment request to include a limit for particulate

contamination as a limiting condition for operation for the diesel generators

and also include a requirement in the Technical Specifications that the fuel

oil be sampled for water. At the time of this inspection, the Office of

Nuclear Reactor Regulation was reviewing the licensee's submittal for

approval.

5.2 Review of the Operability Determination for the Diesel Generator Air

Receiver Outlet Check Valves

During the performance of Procedure 6.3.12.2, which was issued to verify that

the air receiver outlet check valve shuts, the licensee noted that the valve

leaked excessively in the reverse flow direction. The test was initiated with

one air receiver pressurized and the air receiver for the valve being tested

depressurized.

The excessive leakage was identified because the air pressure

between the two air receivers equalized within 1 minute.

To address this degraded condition, the licensee initiated Operability

Determination 93-009 and Deficiency Report 93-020. The licensee's conclusion

on the operability determination stated that, since no criteria had been

provided in Procedure 6.3.12.2 for leakage past the check valve, the' valve was

considered to be operable and, therefore, the diesel generator continued to be

operable.

In addition, the licensee stated that an operability determination

should not nave been written since the check valve met the intent of the

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procedure. The licensee's conclusion on the deficiency report stated that the

test was intended only to prove the movement of the check valve disc and not

the leak tightness; therefore, a degraded condition did not exist. The

deficiency report was administratively closed. The licensee replaced the

check valves on the air receiver inlet and outlet, and on the air compressor

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discharge lines, during the current refueling outage, in accordance with

Maintenance Work Request 93-0854.

The inspectors concluded that the licensee knew that the check valves'were

leaking yet did not evaluate the impact of this leakage on operability. This

approach to operability was of concern because the impact of a degraded

condition on operability was not evaluated.

5.3 Pressure Isolation Valves

The inspectors reviewed the licensee's operability determination and

corrective actions for leaking pressure isolation valves.

5.3.1

Operability Determination for Leaking Shutdown Coolina Suction

Isolation Valves

The inspectors noted that the licensee had generated a maintenance work item

to disassemble inboard and outboard shutdown cooling suction isolation

Valves RHR-M0-18 and -17.

The maintenance work item indicated that both

valves had leaked by the seat, while the plant was operating, and had

pressurized the low pressure piping in the residual heat removal (RHR) system.

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These two valves perform the pressure isolation function between the high

pressure primary coolant system and the low pressure emergency core cooling

systems. These valves also perfors a containment isolation function.

The inspectors reviewed the licensee's operability determination, performed on

May 1, 1992. While the plant was operating, the licensee received the high

pressure alarm on the RHR system suction piping. The normal pressure should

not be above 60 psig, the alarm setpoint was 100 psig, and the piping design

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pressure was 150 psig. The licensee established a path to vent the low

pressure suction piping into the pressure maintenance system. The licensee

measured the leakage through the inboard valve at 0.38 gpm. The licensee was

not able to measure the leakage through the outboard valve. Although the

licensee's Technical Specifications did not specify a limit for pressure

isolation valve leakage, the licensee concluded that the valves were operable

because the leakage was below the standard Technical- Specification limit of

5 gpm for pressure isolation valves. The licensee did not evaluate the

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operability of the containment isolation function of these valves.

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On March 29, 1993, the licensee performed an Appendix J local leak rate test

on Valve RHR-M0-18, with pressure applied in the direction of accident

pressure (Section 4.4 of this report for a discussion of reverse direction

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testing).

The valve failed the test and was documented in Nonconformance

Report 93-075. Upon disassembly for repair and inspection, the licensee found

five cracks in the outboard seat and disc of the valve.

This was the valve

seat that performs the pressure and containment isolation functions.

The failure to promptly correct a condition adverse to quality resulted in

plant operation with containment isolation valves that leaked sufficiently to

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actuate the high pressure alarm in low pressure piping. This is another

apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI (298/9317-01).

5.3.2

Pressure Isolation Valve Testing

The inspectors reviewed the licensee's response to Generic letter 87-06,

" Periodic Verification of Leak Tight Integrity of Pressure Isolation Valves."

This generic letter requested licensees to identify valves that isolate the

high pressure primary coolant system from low pressure emergency core cooling

systems and identify what leak rate testing was performed on these valves.

The licensee identified, in their response to Generic Letter 87-06, four

testable check valves in the core spray injection and low pressure coolant

injection systems, four motor-operated valves in the core spray injection and

low pressure coolant injection systems, two shutdown cooling suction isolation

motor-operated valves, and four air-operated, testable check valve bypass

valves that perform the pressure isolation function. The two testable check

valve bypass valves on the core spray system have been removed. The NRC

included the licensee's testing with other plant's testing to be evaluated

under Generic Issue 105.

The licensee indicated that the four core spray and low pressure coolant

injection valves, and the two shutdown cooling suction isolation valves, were

leak rate tested at containment accident pressure (58 psig in the reverse

direction, see Section 4.4 of this report). No leak rate testing, whether

Appendix J or pressure isolation valve, was performed on the four testable

check valves or the bypass valves and no leak rate testing to verify the

pressure isolation function was performed on any of the pressure isolation

valves.

Since no disassembly / inspection activities were specified for the testable

check valves, the inspectors questioned what basis existed to indicate that

the valses would be capable of performing the pressure isolation function.

During the followup inspection, licensee representatives stated that leak rate

testing would be performed to verify the pressure isolation function during

the current refueling outage. Valves were planned to be tested prior to

startup, with the exception of the core spray injection valves. For the two

core spray injection valves, modifications were necessary, and the licensee

planned to implerent modifications and test the valves during the next outage.

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The inspectors reviewed the testing package and the test results for RHR

Loop B valve testing.

The three valves passed with no leakage.

6 REVIEW OF WORK ITEMS (92720)-

The inspectors reviewed selected maintenance work requests to determine if

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deficient conditions were properly documented-in the licensee's corrective

action processes and were properly resolved.

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6.1 Emergency Condensate Storage Tank Inspection

On March 30, 1993, the inspectors questioned the licensee concerning the

results of an inspection of Emergency Condensate Storage Tanks A and B.

The

inspection of the tanks was conducted under Maintenance Work Request 93-0114,

which was initiated as a result of a January 1993 chemistry department test

that identified high particulate content in the tanks. The inspectors

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identified that workers had observed blistering of the interior coating of

both tanks. No notes were written concerning the specific, as-found

conditions of the tanks and no deficiency report was written. After further

questioning by the inspectors, the licensee issued Maintenance Work

Request 93-1271 to reinspect Tanks A and B.

Based on the reinspection, the licensee developed a plan of action to resolve

the identified concerns, such as paint blistering, paint adherence to the

tank, and corrosion of the tanks. The inspectors reviewed the analysis

provided by an outside contractor concerning the amount of corrosion that

would result from leaving the interior of the tanks unpainted for another

operating cycle.

It appeared from the analysis that no effects detrimental to

the structural integrity of the tanks would be expected.

The inspectors also

questioned the potential for increased radiological hazards from additional

sources of corrosion products available for injection into the primary system

and increased radiological exposure during the final repair of the tank

coatings.

TN: licence was performing an operability evaluation to ensure that the

degraded condition of the emergency condensate storage tanks would not impact

the operability of the high pressure coolant injection or reactor core

isolation cooling systems. The inspectors will review this evaluation when

completed by the licensee. The review of the evaluation is considered an

inspection followup item (298/9317-07).

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On May 4, the inspectors toured the interior of Tanks A and B.

The inspectors

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noted bubbling of paint around the lower one third of Tank A, approximately

10 feet in height from the bottom of the tank to the midheight.

The entire

tank was coated with paint.

Tank B was stripped of. paint, down to bare metal,

from the midline to the top of the tank, approximately 10 feet.

Tank B

appeared to have very little bubbling of the paint on the bottom half, as

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compared to Tank A.

The inspectors also observed various locations where

testing had been performed in accordance with ASTM D 3359-87, " Standard Test

Methods for Measuring Paint Adhesion by Tape Test." The licensee planned to

perform an epoxy paint repair on the various areas within the tanks where the

potential for localized corrosion may exist, including the areas where the

tape test was performed. The upper half of Tank B will be left as bare metal

and, based on the licensee's' analysis, the amount of generalized corrosion

should be within acceptable-limits. The inspectors also reviewed the

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ultrasonic thickness test results performed on both tanks.

Results indicated

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that the tank shell thickness was greater than 3/8 of an inch. The corrosion

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allowance limit was 3/16 of an inch. The licensee planned to repaint both

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Licensee inspection identified blistering of the tank interior coating of both

condensate storage tanks. This condition adverse to quality was not

documented in a deficiency or nonconformance report. The failure to identify

and promptly correct a condition adverse to quality is another example of an

apparent violation of Criterion XVI (298/9317-01).

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7 SERVICE WATER SYSTEM (92720)

The inspectors reviewed the corrective actions taken by the licensee with

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respect to the degraded conditions identified in service water system valves.

-The valves of major interest were the service water RHR heat exchanger

discharge valves (SW-MOV-89A and -898). The heat exchanger receives service

water through a booster pump. Discharge Valves SW-MOV-89A and -89B were

significantly throttled to maintain the service water pressure inside the heat

exchanger above RHR system pressure and also to regulate flow through the heat

exchanger.

A review was performed of the licensee's technical, programmatic, and

procedural activities conducted relative to the design, operation, and

maintenance of the service water system. This review was performed to verify

that the safety-related service water system had been monitored for

degradation, the system complies with the appropriate regulatory, design, and

ISI requirements, the structural integrity of the system is maintained, and

the system complies with the requirements of 10 CFR Section 50.55a(g)(1).

7.1 Service Water RHR Heat Exchanger Discharge Valves SW-H0V-89A and -89B

The source for the service water system was river water, which had a high sand

and particulate content.

Rapid wall thinning attributed to sand abrasion had

been observed in the service water system valves over the years. An orificed

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flow trim and an anti-abrasive epoxy internal coating were added to

Valve MOV-89B during the 1989 refueling outage. During subsequent operations,

the licensee determined that Valve SW-MOV-898 demonstrated the capability to

last three operating cycles without significant wall thinning. A through-wall

hole developed in the body of Valve SW-MOV-89A over the last operating cycle,

after approximately only 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of operation.

At the time that Valve SW-H0V-89A developed the through-wall leak, the other

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train of the SW system was removed from service for the outage. The licensee

performed a temporary repair on Valve SW-MOV-89A and continued to rely upon

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the system to perform its safety-related functions. The licensee, at the

time, did not have an accurate characterization of the impact of the

deficiency on the structural. integrity of the SW system and the licensee did

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not initiate actions to promptly return the opposite train of SW to service.

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The licensee's safety perspective was questionable by relying on a temporary

repair without promptly returning the opposite train to service.

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A replacement valve, considered by the licensee to be identical to the

modified Valve SW-MOV-89B, located in Train B, had been installed in Train A,

for Valve SW-MOV-89A, during the 1991 outage. The licensee expected the valve

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in Train A to provide satisfactory performance for at least three operating

cycles. The replacement valve did not perform, as expected, because the valve

developed a through-wall hole within one cycle of operation.

An examination by the licensee disclosed that the Train A and B valves were

not identical. The Train A valve body had an existing guide rail in very

close proximity to several of the orifice flow holes.

The guide rail

interfered with flow through four of the orifice flow holes. The valve body

through-wall hole originated at the point of the orifice flow interference.

The licensee attributed the through-wall hole to abrasion caused by the high-

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flow velocity and the sand content of the service water. The licensee

repaired the valve body, removed the flow interference portion of the guide

rail, and reinstalled the valve in the system.

The inspectors reviewed the history of Valves SW-M0V-89A and -89B and the

corrective action taken to repair Valve SW-MOV-89A, following identification

of the through-wall hole. The inspectors reviewed system and component

drawings, system-related documentation, photographs of the internal surfaces

of the through-wall hole, and the 1989 through 1991 records of ultrasonic wall

thickness measurements taken on the body of Valves SW-MOV-89A and -898.

The

inspectors interviewed cognizant station and corporate personnel with regard

to issues, questions, and documents on the service water RHR heat exchanger

discharge valves.

The inspectors concluded from the licensee's assessment, based on the 1991

valve examination, that the fact that Valve SW-M0V-898 could last at least

three operating cycles, without replacement of the valve trim, was reasonable.

It was also concluded that the corrective action taken on the repair of the

through-wail hole in the body of Valve SW-MOV-89A was adequate. Although the

licensee classifies the service water system as non-Code, the valve weld

repair was completed with the same processes, procedures, and personnel that

would be used on a Code weld repair. The base material weld repair area was

adequately prepared and examined; the welding was performed using a Code

qualified procedure, welder, and postweld heat treatment; the finished weld

was radiographed to Code acceptance standards; and a hydrostatic test to

110 percent of design pressure was performed.

Based on the reviews performed

by the inspector, it appeared that the repair of Valve SW-MOV-89A was

appropriately performed by the licensee.

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The inspectors reviewed the licensee's plans for additional monitoring for

these valves. The licensee planned to implement additional monitoring for the

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valves that consisted of increased ultrasonic and visual inspections. The

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plan was prepared, documented, and presented to the inspector. Ultrasonic

inspections of Valves SW-MOV-89A and -89B will be increased and implemented

under the current Cooper Nuclear Station Augmented Erosion / Corrosion Program

procedures and criteria.

The ultrasonic inspection frequency will be

increased from once each cycle to each time one of the valves accumulates 168-

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240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> of operating time. The visual inspection of the valve internals

will be increased to once per cycle.

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The licensee planned to evaluate the ultrasonic and visual inspection

frequency after the 1994 refueling outage. The plan may be modified, as

appropriate, based on the inspection results obtained during the outage. The

licensee also proposed to minimize the throttling of the valves to the maximum

extent possible, by limiting booster pump operation. The inspectors concluded

that the planned monitoring actions appeared to adequately address the erosion

concerns identified with these valves.

During review of the replacement of Valve SW-M0V-89A, which was to be

identical to Valve SW-M0V-898, a concern was identified that the licensee did

not appropriately ensure that the valves were the same. As noted in the above

discussion, Valve SW-MOV-89A contained valve trim orifice holes, whereas

Valve SW-MOV-898 did not. At the end of the inspection, the licensee had not

identified the root cause for the differences in valve designs that

established conditions for an erosion / cavitation mechanism that facilitated

the Valve SW-MOV-89A through-wall leak.

A review of the licensee's root cause

determination and final corrective actions will be conducted during a routine

followup inspection of Licensee Event Report 93-014.

Based on the corrective actions taken, the repair of the service water RHR

heat exchanger discharge valves, the review of the associated documentation,

the future monitoring plan, and the discussions with licensee personnel, the

inspectors considered the condition of the valves and planned monitoring -

program to be appropriate.

7.2 Operability of Service Water System Check Valves

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The inservice testing and preventive maintenance performed on the service

water pump discharge check valves, the RHR service water booster pump

discharge check valves, the diesel generator cooler and ventilation service

water supply check valves, and the reactor equipment cooling service water

supply check valves were reviewed. The check valves were included in the

inservice testing program and were open- and closed-exercise tested quarterly

during plant operation, as required by Section XI of the ASME Code. These

valves were included in a scheduled preventive maintenance program, which

required a scheduled periodic disassembly, inspection, and repair or

replacement, as required.

The check valve testing, disassembly, inspection,

and repair were performed using controlled procedures.

The preventive

maintenance performed on these valves was tracked on the licensee's Work Item

Tracking System.

The inspectors reviewed Maintenance Work Requests 92-2862 and 91-2411, which

covered the preventive maintenance procedures used for disassembly,

inspection, and repair of the diesel generator service water supply check

valves and Train D RHR service water booster pump discharge check valve. The

work requests also contained the records of the completed work. The Work Item

Tracking System data of the historical records of the preventive maintenance

performed on the service water pump discharge check valves and RHR service

water booster pump discharge check valves were reviewed. The inspectors also

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reviewed the service water system section of the inservice testing valve

program and found that the check valves were included in quarterly open- and

closed-exercise tests.

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Based on the performance of quarterly testing, review of the preventive

maintenance work packages, and historical maintenance data, the inspectors

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concluded that the licensee had an adequate scheduled testing and preventive

,

maintenance program for the essential check valves in the service water

system.

7.3 Review of Service Water System Structural Integrity

During operation of the service water system, it was noted by the licensee

that a through-wall hole had developed in Valve SW-MOV-89A, as discussed

above. The inspectors determined, upon subsequent discussions with the

licensee, that while other safety-related pumps and valves were within the

scope of the licensee's inservice testing program, piping in the safety-

related service water system was not covered by the scope of the licensee's

ASME Section XI.ISI Program. As a result, the inspectors reviewed the extent

of the inspection and testing that the licensee performed on the system.

7.3.1

Service Water System Structural Integrity

During discussions with licensee personnel, the inspectors determined that the

licensee considers the essential portions, as listed below, of the service

water system as safety-related:

Jacket cooling water to Emergency Diesel Generators 1 and 2

Service water system pump Trains A and C and Trains B and D leading to

the essential Trains A and B service water system headers

Essential Trains A and B of the service water system headers

Trains A and B of the servic; water system, RHR booster system

Trains A and B of the reactor equipment cooling (REC) system

.

The service water system train to the control room ventilation coolers

.

The licensee's engineering staff responded that, while the essential portions

of the service water system were designated as safety-related, the functional

classification of the system was designated by Burns and Roe, the plant

constructor, as Class IVP (i.e., a power generation designation). .The

licensee stated that the Class IVP designation exempted the system from being

covered by the scope of the licensee's ISI program.

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Licensee representatives stated, with respect to inspection and maintenance

activities for the service water system, that no hydrostatic pressure tests

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had been performed on the system to date; however, from 1980 to 1990,

approximately 80 ultrasonic examinations had been performed on 7 or 8

components in the essential portions of the system. These components included

the service water strainer discharge piping, diesel generator jacket cooling

water components, and Valves SW-MOV-89A and -89B.

The licensee provided the

inspectors with the records of the examinations, but added that the

examinations and records of the examinations were not part of a formal

ultrasonic examination program of the service water system. These

examinations were performed, for the most part, prior to the issuance of

Generic letters (GL) 89-08, " Erosion / Corrosion-Induced Wall Thinning," and

89-13, " Service Water System Problems Affecting Safety-Related Equipment,"

which provide guidance on the implementation of more formal inspection

programs. The inspectors reviewed the 1980 to 1990 ultrasonic examination

records and verified that no excessive degradation was indicated in the

examined components.

After issuance of GLs 89-08 and 89-13, the licensee increased the number of

ultrasonic examinations of safety-related service water system components.

Approximately 50 ultrasonic examinations of components in the essential

portions of the service water system had been conducted in 1992 and

approximately 70-80 examinations in 1993. Thus, the augmented program had

just recently been implemented. These ultrasonic examinations were performed

in accordance with the scope of the licensee's approved Augmented

Erosion / Corrosion Program and conducted in accordance with Cooper Nuclear

Station Engineering Procedure 3.10, " Erosion / Corrosion Induced Pipe Wall

Thinning Inspection Program."

The licensee informed the inspectors that, while the service water piping

would normally be exempted from inclusion in the erosion / corrosion program (on

low pressure, low temperature, and high oxygen content criteria), the system

had been added to the augmented program to monitor for abrasion-induced wear

of the service water system piping. The inspectors reviewed the inspection

packets of components in the jacket cooling water system, safety-related

service water headers, and service water system RHR booster system. The

inspectors verified that the components were inspected by Certified Level II

or III nondestructive examination personnel, evaluated, and dispositioned for

wear in accordance with the licensee's augmented erosion / corrosion program.

7.3.2

Licensee Response to GL 89-13

>

The inspectors reviewed the licensee's response to GL 89-13. The inspectors

determined that the licensee's response to GL 89-13 was sufficient to address

the macrofouling and microfouling concerns stated in the GL.

Specifically,

the inspectors determined that the licensee required an inspection of the

service water system intake structures, strainers, and heat exchangers, at

regular intervals, to monitor for debris or for infestation by asiatic clams

or zebra mussels.

The inspectors also verified that the licensee had implemented a program for

monitoring the extent of silt deposition in low flow or stagnant regions in

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the service water piping. The program appeared to be sufficient in

identifying problem areas of silt deposition. The program included corrective

action recommendations in regard to silting problem areas.

The licensee's GL 89-13 program requires regular ultrasonic inspections of the

service water system piping. These inspections were performed in accordance

with the licensee's augmented erosion / corrosion program. The GL 89-13 program

also calls for a system flow rate determination and a post-LOCA flow analysis

once per operating cycle. The licensee furnished the inspectors with the

latest analysis. The inspectors verified that the flow analysis was performed

properly and that the flows through the service water system were capable of

removing design basis accident heat loads.

The inspector.s concluded that the

licensee appropriately responded to the information contained in GL 89-13.

7.3.3

Service Water System Maintenance Activities

The inspectors reviewed the instructions for replacement of tees in the jacket

cooling water system for Emergency Diesel Generators 1 and 2.

The ultrasonic

data in the inspection packets for these tees, designated SW-DG-1-T-3 and

SW-DG-2-T-3, indicated that some areas of the walls of the tees had worn below

the minimum wall thickness acceptance criteria. The inspectors verified that

the components were properly dispositioned for replacement.

The inspectors discussed replacement of the tees. The licensee stated that

repairs or replacements of the service water system were performed in

accordance with the licensee's original code of construction,

USAS B31.1.0-1967, which is allowed by ASME Section XI, Articles IWA-4000 and

-7000.

The licensee did not normally consider temporary non-Code repairs a

conservative method of repairing excessively degraded safety-related

components.

The inspectors reviewed the maintenance packets that

dispositioned the replacement of Tees SW-DG-1-T-3 and SW-DG-2-T-3.

The

inspectors verified that the replacements were performed by qualified welders,

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in accordance with qualified weld procedures. The inspectors also verified

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that qualified quality assurance personnel dispositioned the welding process

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at the specified hold points.

The inspectors noted that the post-weld integrated system leakage tests for

repaired or replaced components were performed at design pressure, as opposed

to 110 percent of design pressure, as would be required for Class 2 or 3

,

components under Section XI of the ASME Code. However, repairs or

'

replacements of service water components, including the leakage tests, were

done in accordance with the requirements, applicable to a Burns and Roe

Class IVP, of a USAS B31.1.0 system.

7.3.4

Compliance with 10 CFR 50.55a(q)(1)

This regulation requires, for plants with .onstruction permits issued prior to

January 1, 1971, that safety-related components, which are not part of the

reactor coolant pressure boundary, meet the requirements applicable to the

ASME Code Class 2 or 3 components. This regulation would require that the

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essential portions of the service water and REC systems be covered by the

scope of the licensee'sSection XI ISI program, unless specifically granted

relief or exempted from the requirements by the Office of Nuclear Reactor

Regulation. To date, no relief or exemption from the ASME Section XI ISI

requirements had been granted by the Office of Nuclear Reactor Regulation

relative to essential portions of the service water or REC systems.

The licensee stated that the service water system was not included in the

licensee'sSection XI ISI Program, based on the system's current

classification, as a Burns and Roe Class IVP system.

The licensee expanded

upon this position by stating that the intent of 10 CFR Section 50.55a(g)(1)

was to match the construction requirements for safety-related systems,

structures, and components to applicable ISI requirements. As such, Class IVP

systems and piping would not be included in the licensee's ISI Program.

The licensee further stated that the NRC implicitly approved the current

status of the licensee'sSection XI ISI program in a number of cover letters

transmitting ISI safety evaluation reports to the licensee.

These safety

evaluations were issued only to address the ISI relief requests submitted by

the licensee and did not constitute a full review of the licensee's entire

Section XI ISI Program.

The inspectors reviewed the documents that provided the licensing basis for

the facility. The inspectors determined that the facility operating license

was issued on January 18, 1974. The facility was licensed to the information

provided in the original Final Safety Analysis Report (FSAR), Amendment 7, as

amended through Licensing Amendments 8-30.

According to the FSAR, the service water system was designed to USAS

Code B31.1.0-1967. This Code was the original design code of record, as

approved in the FSAR for the facility. Accordingly, the facility was licensed

prior to the date when reference to the ASME code classifications became

effective in 10 CFR Section 50.55a. The licensee's original FSAR was approved

without any ASME system classifications applicable to ASME Code Class A, B,

and C (now Class 1, 2, and 3) systems and components.

Instead, systems were

originally assigned a Burns and Roe classification system. The codes and

standards, and Burns and Roe functional and seismic classifications, which

apply to the facility, may be found in Appendix A to Volume 7 of the original

FSAR.

The inspectors concluded that the Burns and Roe construction classification of

the service water and reactor equipment cooling systems as Class IVP was

inappropriate or nonconservative from a system function perspective and that

the licensee's use of the Class IVP classification as a basis for not

including the systems in the ISI program was inappropriate.

As noted above, the licensee's inspection and maintenance program for the

essential service water system was performed in accordance with the licensee's

augmented erosion / corrosion program.

This program did not satisfy ASME Code

requirements for Code Class 2 and 3 components.

Section XI of the ASME Code,

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and hence the licensee'sSection XI ISI Program, would require that the

essential portions of the systems he hydrostatically tested to 110 percent of

design pressure r

2 per every 10 year operating interval and following any

Code repair or ..giacement welding.

10 CFR Section 50,55a(g)(1) requires, in part, for plants with construction

permits issued prior to January 1,1971, that safety-related components that

are not part of the reactor coolant pressure boundary meet the requirements

applicable to the ASME Code Class 2 or 3 components. The construction permit

was issued on June 4, 1968; therefore, the licensee was required to apply the

requirements for ASME Code Class 2 or 3 components to safety-related

components in the plant that are not included among the components for the

reactor coolant system pressure boundary.

10 CFR Section 50.55a(g)(4) requires, in part, that throughout the service

life of a boiling, water-cooled nuclear power facility, components (including

supports), which are classified as ASME Code Class 1, 2, and 3, must meet the

requirements, except design and access provisions and preservice examination

requirements, set forth in Section XI of the Code.

10 CFR Section 50.55a(g)(5)(i) requires, in part, that the ISI program for a

boiling, water-cooled nuclear power facility, must be revised by the licensee,

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as necessary, to meet the requirements of 10 CFR Section 50.55a(g)(4).

Inspectors, in consultation with NRC's Office of Nuclear Reactor Regulation,

concluded that, according to 10 CFR Section 50.55a(g)(1), (g)(4), and (g)(5),

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the licensee would be required either to include the essential portions of the

service water and REC systems in the Section XI ISI Program, or to include the

essential portions of the service water and REC systems in the licensee's

originally licensed ISI Program and update the requirements relative to these

systems to Section XI equivalency.

Thus, since February 12, 1976, when the

revisions to 10 CFR Section 50.55a(g) went into effect, the licensee had

failed to revise the Section XI ISI program to include the essential portions

of the service vater and REC system piping. This is an apparent violation

(298/9317-08).

7.3.5 Conclusions

The review of the service water system indicated that the licensee conducted a

sufficient number of ultrasonic examinations for the purpose.of monitoring the

structural integrity of the system. Although the licensee is in apparent

violation of the collective requirements of 10 CFR Section 50.55a(g)(1),

-(g)(4), and -(g)(5), the number of inspections performed provide a reasonable

assurance that the structural integrity of the service water system will be

maintained during the next operating cycle.

Furthermore, the licensee's

program for addressing biofouling, silt, and debris in the service water

system provided a reasonable assurance that service water flow through the

service water system was capable of removing shutdown, normal operational, and

design-basis accident heat loads.

Nonetheless, the apparent violation is

significant because the licensee's failure to consider the SW piping as ASME

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Code piping had resulted in reliance of the system to perform with temporary

repairs, no hydrostatic pressure tests have been performed since original

construction, and no hydrostatic pressure tests on piping have been performed

after repairs.

8 LEAK RATE TESTING OF PENETRATIONS (92701)

The inspectors reviewed selected portions of the licensee's program for leak

rate testing of 1-inch or smaller primary containment penetrations. This

review was performed based on concerns identified with the testing of the

penetrations for the hydrogen / oxygen analyzers.

See Section 4.2.3 for a

_

discussion of the concerns associated with the analyzers.

Based on the review of the selected portions of the licensee's penetration

testing program, the inspectors noted no problems with the licensee's

implementation of the testing program. However, a concern was identified with

the mechanism implemented by the licensee for the handling of license changes

approved by the NRC.

On May 4, 1992, the licensee requested that the Technical Specifications be

amended to remove the specific information provided in Technical Specification-

Tables 3.7.2, 3.7.3, and 3.7.4, which address penetration testing

requirements. The licensee stated that the information would be placed in the

Updated Safety Analysis Report and a plant procedure. On January 7,1993, the

NRC approved the licensee's Technical Specification amendment request to

remove the tables and place them in a plant procedure and the Updated Safety-

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Analysis Report. The inspectors noted that the licensee had not placed the

specific information related to penetration testing in a plant procedure at

the time of this inspection and also noted that the licensee had already

completed penetration testing during the current refueling outage. The

inspectors reviewed Procedure 6.3.1.1, " Primary Containment Local Leak Rate

Tests," used to control the performance of penetration testing, and noted that

the procedure adequately tested the penetrations, even though the specific

information from the Technical Specification tables had not yet been included.

The licensee's program for controlling information provided in license

amendments was contained in Procedure 0.29, " Administrative Control of License

Amendments." This procedure required that a license change request form be

completed whenever a license amendment was received by the licensee. The

intent of this form was to ensure that changes required to be made to

documentation, as a result of a license amendment, were fully implemented. A

license change request form was issued for the amendment the licensee received-

in January 1993; however, the changes had not been made.

Based on the

licensee completing the change form, reasonable assurances existed that

Procedure 6.3.1.1 would have eventually been updated.

As a result of this review, the inspectors noted that Procedure 0.29 did not

contain a time limit for when procedure changes were required to be made after

receipt of a license amendment.

The licensee, in response to this

observation, stated that a change would b2 made, within 60 days of the end of

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this inspection, to Procedure 0.29 to specify a time limit for procedural

changes affected by the issuance of a license amendment.

In addition, the

licensee stated that a review of open license change request forms would be

performed prior to startup to verify that open request forms had been properly

dispositioned.

Subsequent to the end of this inspection, during a call with

the licensee, the inspectors were informed that open request forms had been

reviewed and no procedure changes were required prior to plant startup.

9 MANUAL VALVE TESTING (71707)

"

The inspectors reviewed the licensee's inservice testing program to ascertain

that manual valves were being tested in a manner that verified their ability

to perform their safety-related function. The inspectors selected seven

manual valves for review. The criteria used for the selection was that the

valves were required, by the licensee's procedure, to be operated to mitigate

the consequences of an accident. The valves selected were identified in

Emergency Operating Procedure 5.8.7, " Primary Containment Flooding Systems

(PC/L-2)," Revision 1.

The inspectors reviewed preventive maintenance records, which would be

required in order for a valve to be routinely cycled, to determine if the

seven selected valves were being exercised. Review of maintenance records

indicated that three of the valves have not been cycled by preventive

maintenance items since they were originally installed in the plant. The

inspectors reviewed this finding with the licensee and the inspectors were

,

informed that they did not have any manual valves in the inservice testing

program.

,

In discussions with licensee representatives, it was established, with respect

to the licensee's position regarding the cycling of manual valves, that the

inservice testing program requirements, as stated in ASME Section XI, 1979

Edition, through the Winter 1991 addenda, require cycling of valves if the

valves are in Class 1, 2, or 3 systems.

In addition, the ASME requirements

state that only those valves required to mitigate the consequences of a design

basis accident or to place the plant in a hot shutdown condition ..e required

to be cycled.

The valves identified by the inspectors were not included within the

requirements discussed above.

Procedure 5.8.7 was considered to be an E0P

Support Procedure and, as such, was not included in the group of procedures

that require cycling of manual valves.

The inspectors identified that the

diesel fuel oil tank crossconnect valves were required to be manually operated

during a design basis event (i.e., loss of offsite power concurrent with a

LOCA) and these valves were not in the licensee's inservice testing program.

The licensee stated that these specific valves were excluded since the diesel

fuel oil system was not considered to be a Class 1, 2, or 3 system. The

licensee stated that the valves were cycled when required for operational

evolutions, such as filling the diesel fuel oil tanks; however, a preventive

maintenance item did not exist to ensure that the valves were routinely

cycled.

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As discussed in Section 7.3.4 of this report, an apparent violation

(298/9317-09) was identified with the method used by the licensee for

classification of plant systems. This issue remains unresolved pending review

of the licensee's actions that may be required to test the appropriate manual

valves (298/9317-9).

Although the valves discussed above were excluded from the inservice testing

program through the regulations applicable to the Cooper Nuclear Station, the

operation of specific manual valves in the plant was required to mitigate the

consequences of an accident, even though the accident may be beyond the scope

of the design basis accidents.

For this reason, the inspectors were concerned

.

that, if the licensee was faced with having to operate a manual valve to place

the plant in cold shutdown, it would not be known if the valve could be

operated.

As a result of an inspection finding at another nuclear facility, the

licensee, in November 1992, initiated a review to determine whether or not

manual valves should be periodically cycled. The program coordinator was

developing the criteria for determining which manual valves should be placed

in the program. When the criteria are established, the licensee will

implement preventive maintenance activities for cycling of the valves.

The

Site Manager stated that this effort will be completed by the end of 1993.

10 LICENSEE REVIEWS

After the first week of inspection, the licensee committed to conduct reviews

to identify any existing items that may not have been adequately resolved. On

April 21, 1993, the licensee established an overview group (Corrective Actions

Program Overview Group) with the assigned charter to independently. assess the

adequacy of documents.

The group consisted of relatively senior site managers

and was assigned to review open nonconformance reports, closed nonconformance

reports within the last 2 years, and deficiency reports and assess _ maintenance

work items for proper documentation and resolution of deficiencies. The group

also interviewed site personnel who were involved with operations,

surveillance testing, and maintenance of the plant.

Inspectors reviewed a preliminary list of items that the licensee had

identified that needed additional review or resolution. The types of items

the licensee had identified indicated that the overview group was looking at

past items with a questioning attitude.

At the completion of the inspection, the licensee indicated that the overview

group had essentially completed personnel interviews. The group had also made

substantial progress in completing document reviews.

11 ELEVATED RELEASE POINT MONITORS (71707)

During emergency plan implementation walk-throughs, inspectors questioned the

design of the power supply for the elevated release point radiation monitors.

It was observed in the simulator that, during an accident with a loss of

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offsite power, these monitors would lose electrical power and would not

automatically re-energize. Operators would then use a manual method to

estimate the radioactive material release rate. During this inspection,

inspectors verified that the design of the monitor power supply was in

accordance with Regulatory Guide 1.97 and reviewed the licenses's corrective

actions to provide procedural guidance to explicitly direct plant operators to

restore power to these monitors after a loss of offsite power.

Inspectors reviewed the in-process changes to Station Procedure 4.15,

" Elevated Release Point 2nd Building Radiation Monitoring Systems," Emergency

Procedure 5.2.5, " Loss of Normal AC Power - Use of Emergency AC Power," and

the annunciator response procedures. The licensee added a new section to

Procedure 4.15 which would give operators the detailed instructions on

returning the monitors to service after a loss of power. Emergency

Procedure 5.2.5 was being revised to add a step directing operators to restore

power to the elevated release point using Procedure 4.15.

The annunciator

response procedure for " Vent Monitor Power Loss" was changed to direct the

operators to Procedure 4.15 to return the monitors to service.

Inspectors concluded that the proposed procedures changes gave the operators

detailed and apparently adequate procedural guidance to return the elevated

release point monitor to service after a loss of offsite power.

10 CFR Part 50, Appendix B, Criterion V, states that activities affecting

quality shall be prescribed by documented instructions, procedures, or

drawings of a type appropriate to the circumstances and shall be accomplished

in accordance with these instructions, procedures, or drawings.

Instructions,

procedures, or drawings shall include appropriate quantitative acceptance

criteria for determining that important activities have been satisfactorily

accomplished.

Procedure 4.15 and Emergency Procedure 5.2.5 were not appropriate to the

circumstances in that no instructions were provided to specify how or when to

return the elevated release point radiation monitor to service after a loss of

offsite power. This is an apparent violation (298/9317-04).

12 FOLLOWUP OF OPEN ITEMS (92700)

12.1

Procedures

NRC Inspection Report 50-298/93-201 identified three examples where station

procedures or approved instructions were not followed.

These included:

Overtime deviation requests were on file and not identified

(Deficiency 298/93201-07).

Workers did not follow a maintenance work request

(Deficiency 298/93201-10).

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Control room operators did not log the change in status of critical

plant components, such as primary and secondary containment

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(Deficiency 298/93201-12).

NRC Inspection Report 50-298/93-13 identified two examples where station

procedures or approved instructions were not followed. These included:

A station operator did not use or follow procedures when racking-out an

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electrical breaker, resulting in a loss of shutdown cooling (Unresolved

Item 298/9313-01).

Two workers entered the drywell radiologically controlled area without

signing the special work permit (Unresolved Item 298/9313-02).

10 CFR Part 50, Appendix B, Criterion V, states that activities affecting

quality shall be prescribed by documented instructions, procedures, or

drawings of a type appropriate to the circumstances and shall be accomplished

in accordance with these instructions, procedures, or drawings.

Instructions,

procedures, or drawings shall include appropriate quantitative acceptance

criteria for determining that important activities have been satisfactorily

accomplished.

The above concerns were examples of failure to accomplish activities affecting

quality in accordance with procedures. The details of the occurrences were

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documented in the referenced reports. This report closes the above items and

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opens an apparent violation (298/9317-04), with the above items as examples.

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12.2 Other Items

The review documented in Section 7.3.2 of this report closes Unresolved

Item 298/93201-11.

This report also closes Deficiency 298/93201-14 and opens Unresolved

Item 298/9317-07, pending additional NRC review.

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ATTACHMENT I

I PERSONS CONTACTED

• D. Dageford, Lead Mechanical Systems Engineer

A. Wiese, Lead Engineer Root Cause & Corrective Actions

• B. Nitsch, SW System Engineer

• F. Schizas, Mechanical Engineer

• B. Crow, Lead Mechanical Engineer

• K. Curry, Senior Mechanical Engineer

• D. Mullen, Mechanical Engineer

B. Seidl, Electrical /I&C Engineer

• M. Spencer, Engineering Programs Supervisor

R. Moberly, Electrical /I&C Engineer

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• R. Koch, Lead Operations Engineer

• H. Dean, Nuclear Licensing and Safety Supervisor

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• J. Meacham, Site Manager

• G. Smith, QA Manager

• C. Estes, CAP 0G Member - CNS

• R. Gardner, Plant Manager

• S. Peterson, Sr. Manager of Operations

• R. Sanchez, CAP 0G Member - CNS

• S. Freborg, Plant Engineering Supervisor

• B. Swantz, Project Manager

• R. Wenzl, NED Site Manager

• J. Flaherty, CNS Engineering Manager

• C. Moeller, CNS Technical Staff Manager

• A. Gray, Sr. Operations Engineer

• L. Bray, Regulatory Compliance . Specialist

• P. Ballinger, Operations Engineering Supervisor

• R. Schultz, Sr. Mechanical Engineer

• J. Swanson, Sr. Mechanical Engineer

• R. Krause, Maintenance Engineer

• K. Walden, Configuration Management Manager

• D. Robinson, QA Manager - G.0.

In addition to the personnel listed above, the inspectors contacted other

personnel during this inspection period.

• Denotes personnel that attended the May 7 exit meeting.

2 EXIT. MEETINGS

-Two exit meetings were conducted, one on April 2 and another on'May 7. -During

these meetings, the inspectors reviewed the scope and findings of the report.

The licensee did not-identify as proprietary any information provided to, or-

reviewed by, the inspectors.

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ATTACHMENT 2

Containment Isolation Valves Tested in a Direction Other than Accident

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Pressure Without Determining that the Results were Equivalent or Conservative

RHR-MOV-M018

20 inch

Flex-wedge gate

RHR-MOV-M025A

24 inch

Flex-wedge gate

RHR-MOV-M025B

24 inch

Flex-wedge gate

RWCU-M0V-M015

6 inch

Flex-wedge gate

RW-A0V-A082

3 inch

Flex-wedge gate

CS-MOV-MOSA

3 inch

Flex-wedge gate

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CS-MOV-M05B

3 inch

Flex-wedge gate

MS-MOV-M074

3 inch

Flex-wedge gate

HPCI-MOV-M015

10 inch

Flex-wedge gate

,

CS-M0V-M012A

10 inch

Flex-wedge gate

CS-M0V-M0128

10 inch

Flex-wedge gate

RW-A0V-A094

3 inch

Flex-wedge gate

PC-MOV-1311MV

1 inch

Solid-wedge gate

RR-A0V-741AV

3/4 inch

Y-globe

PC-M0V-1302MV

1 inch

Solid-wedge gate

PC-MOV-306MV

2 inch

Solid-wedge gate

RCIC-MOV-M015

3 inch

Flex-wedge gate

PC-MOV-1306MV

1 inch

Solid-wedge gate -

RHR-M0V-M031A

10 inch

Flex-wedge gate

RHR-MOV-M031B

10 inch

Flex-wedge gate

PC-M0V-1304MV

1 inch

Solid-wedge gate

RHR-MOV-M021A

4 inch

Flex-wedge gate

RHR-M0V-M021B

4 inch

Flex-wedge gate

RHR-MOV-M016A

4 inch

Flex-wedge gate

RHR-MOV-M016B

4 inch

Flex-wedge gate

PC-M0V-305MV

2 inch

Solid-wedge gate

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