ML20135E529

Insp Rept 50-298/96-25 on 961118-22 & 1209-13.Violations Noted.Major Areas Inspected:Review of Licensee Programs for Corrective Action & self-assessment Process,Activities of Safety Review Committee & Operating Experience Feedback

ML20135E529
Person / Time
Site:	Cooper
Issue date:	03/04/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20135E504	List: ML20135E501 ML20135E520 ML20135E529
References
50-298-96-25, NUDOCS 9703070124
Download: ML20135E529 (43)

See also: IR 05000298/1996025

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ENCLOSURE 2 l

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U.S. NUCLEAR REGULATORY COMMISSION j

REGION IV j

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Docket No.: 50-298  !

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License No.: DPR-46

Report No.: 50-298/96-25

Licensee: Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: P.O. Box 98

Brownville, Nebraska l

Dates: November 18-22 and December 9-13,1996

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inspectors: T. Stetka, Team Leader  !

R. Azua, Reactor Inspector ,

P. Goldberg, Reactor inspector

P. Qualls, Reactor inspector

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P. Madden, Senior Fire Protection Engineer j

T. Eaton, Fire Protection Engineer-Intern

Approved By: C. VanDenburgh, Chief, Engineering Branch l

Division of Reactor Safety

Attachment: Supplemental information

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9703070124 970304

PDR ADOCK 05000298

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EXECUTIVE SUMMARY

Cooper Nuclear Station

NRC Inspection Report 50-298/96-2

This inspection evaluated the effectiveness of the licensee's controls in identifying,

resolving, and preventing issues that degrade the quality of plant safety. Specifically, the

inspection team reviewed the licensee's programs for the corrective action and self

assessment process. The team reviewed the activities of the safety review committees

and operating experience feedback program. The inspection also included a review of the

fire protection program to determine if the corrective actions taken to resolve the fire

protection program deficiencies identified in Licensee Event Report 96-06 were thcough

and complete. The inspection covered a 4-week period with 2 weeks of onsite inspection.

Operations

• The corrective action program provided an effective method for reporting,

prioritizing, and tracking licensee findings, in addition, the licensee's efforts to

educate plant personnel regarding the problem identification reporting process, and

their continuing efforts to keep the plant management informed as to the progress

of the corrective action program was notable (Section 01.1).

• Operations had done a very good job of identifying and reporting plant problems

(Section 01.1).

• The Safety Review and Audit Board and the Condition Review Group were 1

effectively implementing their license requirements. However, the Station 1

Operations Review Committee f ailed to review station operations to detect potential l

nuclear safety hazards. This was identified as a violation of the Technical

Specifications (Section 01.2).

• The backlog of open items for the Operations Department was low and the licensee

was effectively managing this backlog. In addition, operations was appropriately

resolving emergent issues and had good engineering support (Sections 07.1

and 07.2).

• The operator aids and operator workaround programs were properly controlled

(Section 07.3).

Maintenance

• The inspection team noted that mechanical maintenance had a low plant problem

reporting level (Section 01.1).

• The backlog of open items for the maintenance department was low and the  !

licensee was effectively managing this backlog. However, problems with 1

maintenance planning workloads and a cumbersome maintenance work request l

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process combined with an upcoming refueling outage, were considered to be

precursors to increased backlogs. The licensee was taking action to address this

increase (Section M7.1).

Maintenance was appropriately resolving emergent issues. However, an issue was

identified where the completed corrective actions for a plant problem involving

personnel training on prejob briefings and the use of a prejob briefing form were not i

complete and contradicted the proposed corrective actions (Section M7.2). l

Quality assurance audits were thorough and critical as evidenced by the quality

assurance audits of design control and corrective maintenance. These audits t

identified issues similar to the issues identified by the NRC inspection. The quality I

assurance department's aggressive efforts in identifying licensee problems was

notable (Sections M7.3 and E7.8).

Enaineerina

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Compared with other single unit nuclear plants, engineering had a high open item

backlog of approximately 3000 items. Although a slight decrease in the backlog ,

was noted due to a recently initiated backlog reduction effort, the team was I

concemed that the licensee's efforts to address this issue had not been effective j

(Section E7.1).

Engineering involvement with operability determinations, maintenance work orders,  !

temporary modifications and engineering problem requests was appropriate and

effective (Sections E7.2, E7.3, and E7.5).

• The licensee effectively used their design criteria documents, which were

maintained as living documents (Section E7.6).

Due to a high amount of emergent work, system engineers indicated they were

restricted in their ability to proactively approach problems involving their systems j

(Section E7.4),

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• In general, engineering properly dispositioned plant problems (Section E7.6). )

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The inspection identified an unresolved item involving the acceptability of increased

emergency diesel generator cylinder exhaust differential temperatures. The licensee i

had increased the differential temperature limit, in lieu of identifying and correcting j

the cause of the temperature increase (Section E8.1.2). 1

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The licensee's engineering self assessment and self-assessment followup were

thorough, comprehensive, and resulted in many good findings. These self-

assessment findings were consistent with those identified by the NRC team.

However, due to resource constraints in the engineering department, the resolution

of these self-assessment findings was not effective in fact, the followup

assessment indicated that there was a concern in the engineering organization

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regarding the commitment of management, the availability of resources, and the '

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authority of the finding owners to implement action plans effectively (Section E7.7).

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The operating experience review program was effective in identifying, determining

applicability, tracking, and responding to both NRC and industry events 1

, (Section E7.9). l

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Plant Suonort

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• Prompt and effective corrective actions were taken to resolve deficiencies identified

3 while re-evaluating the 10 CFR Part 50, Appendix R safe shutdown analysis. As a

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result of these efforts, the licensee identified additional examples of violations of

Appendix R. However, in accordance with Section Vll.B.4 of the " General

l Statement of Policy and Procedures for NRC Enforcement Actions," NUREG 1600,

, these violations were not cited nor considered for escalated enforcement because

they were identified as a result of the licensee's corrective actions for a previous

! Severity Level ill violation (EA 96-94) (Section F8).

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l * The inspection identified a corrective action violation involving ineffective corrective

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action for the control of transient combustible material (Section F8).

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j * The inspection identified three unresolved items involving the licensee's Appendix R

fire protection program. These items involved

i The use of automatic depressurization and the core spray systems as an

alternate post-fire shutdown method did not appear to meet the requirements

of Appendix R.

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, The originallicensing basis for the fire detection system was unclear.

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The originallicensing basis of the fire suppression system in the area where

the reactor recirculation pump motor generator sets were located, was

unclear.

These items will be referred to the Office of Nuclear Reactor Regulation for

l clarification of the Appendix R and originallicensing conditiorn (Section F8). l

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TABLE OF CONTENTS

EX EC UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

R e p o rt D e t a il s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. O P E R AT I O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01 CO N D U CT O F O PER ATIO N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.1 Corrective Action Program implementation . . . . . . . . . . . . . . . . . 1

01.2 Safety Review Committee Activities ..................... 3

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07 QUALITY ASSURANCE IN OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . 4  !

07.1 Control of Open item Backlog . . . . . . . . . . . . . . . . . . . . . . . . . . 4

07.2 Condition Report and Problem identification Report Reviews . . . . 4

07.3 Operator Aids and Workarounds . . . . . . . . . . . . . . . . . . . . . . . . 5

07.4 Self-Assessment Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

11. M AINTEN ANCE . . . . . . . . . . . . . . . . . . . ............................. 7

M7 QUALITY ASSURANCE IN MAINTENANCE ACTIVITIES . . . . . . . . . . . . 7

M7.1 Control of Open item Backlog . . . . . . . . . . . . . . . . . . . . . . . . . . 7

M7.2 Condition Report, Problem identification Report and

Maintenance WorF Request Reviews . . . . . . . . . . . . . . . . . . . . . 8

M7.3 Quality Assurance Audit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 j

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111. E N G I N E E R I N G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 l

E7 QUALITY ASSURANCE IN ENGINEERING ACTIVITIES . . . . . . . . . . . . . 10

E7.1 Control of Open item 8acklog . . . . . . . . . . . . . . . . . . . . . . . . . 10 5

E7.2 Operability Determinations and Corrective Maintenance Work 1

Orders ......................................... 11

E7.3 Temporary Modifications ............................ 12

E7.4 System Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

E7.5 Engineering Project Requests . . . . . . . . . . . . . . . . . . . . . . . . . . 13  !

E7.6 Engineering Disposition of Problem identification Reports . . . . . . 13

E7.7 Self- Assessment Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

E7.8 Quality Assurance Audit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 l

E7.9 Operating Experience Feedback . . . . . . . . . . . . . . . . . . . . . . . . 18 l

E8 MISCELLANEOUS ENGINEERING ISSUES . . . . . . . . . . . . . . . . . . . . 19 l

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l I V. Pl a nt S u p po rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 l

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F8 MISCELLANEOUS FIRE PROTECTION ISSUES . . . . . . . . . . . . . . . . . . . 22

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V. MANAGEMENT MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

X1 EX IT M E ETI N G S U M M A R Y . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . 28

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Report Details

1. OPERATIONS

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01 CONDUCT OF OPERATIONS I

01.1 Cortective Action Proaram imolementation

a. Insnection Scope

The team reviewed the administrative procedures that control the identification,

evaluation, and resolution of identified problems. In addition, the team interviewed

five individuals involved with the implementation of the licensee's problem

identification process.

b. . Observations and Findinas

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The licensee ~s corrective action program was described in Administrative i

Procedure 0.5, " Problem Identification and Resolution," Revision 8. This program I

was in effect since April 1996, and constituted a change to the former program. In  ;

this new program, problem identification reports replaced condition reports as the

reporting mechanism for plant identified problems. When the new program was

introduced, the corrective action program staff held a number of meetings to

provide training on the new reporting documentation, and to provide guidance on  ;

the threshold for reporting. As a result of this training, the number of reported  !

problems increased. This was noted by the team during review of problem

identification reports. This was further corroborated when operations and

maintenance personnel interviewed indicated that they were not hesitant to write i

problem identification reports for identified problems, regardless of how small or l

insignificant they may seem.

The team found that two levels of review were performed on each problem

identification report. The first levelinvolved a determination of the immediate

safety significance of the identified problem by a daily condition review group

meeting. During this meeting the problem identification report was designated as  ;

either a signitm mt condition adverse to quality, condition adverse to quality, work

item, departmental disposition, trending, or closure based on actions taken. This

process was used to determine if a root-cause analysis was needed. For a

significant condition adverse to quality, a mandatory root-cause analyses was

performed.

Following a determination of safety significance, the second review level set a

priority for the proposed corrective actions. Each corrective action was given a

priority number from one to six (most to least significant) in accordance with

Nuclear Power Group Directive 4.12, " Work Prioritization." Once an action item

was assigned a priority number, the action was assigned to one of the departments

for closure responsibility. Each item, depending on its assigned priority, was

required to be completed within a specific time period.

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When a department anticipated that the action would not be closed within the

specified time period, the department would submit an extension request that

stipulated the cause of the delay. Approval of the extension request could be

obtained from the responsible department manager or a corrective action review  !

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board chairman. This afforded licensee management the opportunity to assess the

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significance of the delay, and to take action if the delay was unacceptable. r

The team found that the corrective action program staff were proactive in their

efforts to provide information regarding the status of the corrective action program. l

One example of this was a series of graphs that depicted the percentage of findings

identified within each department (operations, maintenance, etc.). The graphs

provided a comparison between the percentage of findings that were identified by ,

personnel within each department versus those findings identified in each

department by personnel outside the departments.

The team noted that more than 50 percent of the findings in the maintenance

department were identified by personnellocated outside these departments. The

corrective action program staff provided a breakdown of the maintenance

department findings. These graphs indicated that while the instrumentation and

controls personnelidentified 60 percent of the totalinstrumentation and controls

findings, the mechanical maintenance staff only identified 25 percent of the total

mechanical maintenance findings.

As a result of the corrective action program staff findings, the maintenance .

department issued a problem identification report to determine the reason for the 25

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percent finding level in mechanical maintenance, in the interim, maintenance

, management personnel indicated that they planned to hold discussions with each of t

their departments regarding the problem identification report process and the

corrective action program staff findings.

The team noted that a similar program did not exist for engineering. However, the

team was informed that the corrective action program staff planned to provide a

similar status program for engineering.

c. Conclusions

The licensee's corrective action program provided an effective method for reporting,

prioritizing, and tracking licensee findings. The corrective action program staff's

efforts to educate plant personnel regarding the problem identification reporting  ;

process, and their continuing efforts to keep the plant management informed as to 1

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the progress of the corrective action program was notable. Licensee efforts in

identifying and reporting plant problems was found to be very good overall, but

some areas (e.g., mechanical maintenance) needed improvement. Procedural

compliance with the problem identification report process was good.

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01.2 Safety Review Committee Activities

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a. Insoection Scone

The licensee's safety review committees consisted of the onsite Station Operations

Review Committee and the offsite Safety Review and Audit Board. The licensee

also convened condition review group meetings. The condition review group

reviewed emergent problem identification reports and dispositioned these reports in

accordance with their corrective action program (see Section 01.1). The team l

reviewed approximately 73 meeting minutes for the Station Operations Review

Committee for the period of July 2 through November 25,1996. The team

reviewed Safety Review and Audit Board meeting minutes for the May 24, July 26,

and September 27,1996, meetings. I

in addition, the team attended two Station Operations Review Committee meetings, I

three Safety Review and Audit Board subcommittee meetings, and two condition j

review group meetings to verify that the license conditions were satisfied and that '

the reviews were effective in identifying problems,

b. Observations and Findinas l

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The team noted that the Safety Review and Audit Board and the condition review

group were performing all activities required by license conditions and implementing ,

procedures. The observed Safety Review and Audit Board subcommittee meetings {

included critical and in-depth discussions of the reviewed activities. The team noted '

that one Safety Review and Audit Board subcommittee concluded that while the

licensee was effective in identifying plant problems they were not as effective in

correcting or resolving those problems. )

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As a result of the team's Station Operations Review Committee meeting minutes  !

review and the attendance at two Station Operations Review Committee meetings,

the team observed that not alllicense requirements were being implemented.

Specifically, the Technical Specification requirement to review station operation to

detect potential nuclear safety hazards was not being performed.

In response to this finding, the licensee stated that they were reviewing completed

operations activities and proposed procedure changes, which they believed met the

intent of this Technical Specification requirement. However, following additional

discussions, the licensee agreed that they were not reviewing potential safety

j hazards that could occur during station operations. '

Technical Specification 6.2.1.A.4.e requires the Station Operations Review I

Committee to review station operations so that potential safety hazards could be  !

detected. The failure to review station operation to detect potential safety hazards

is a violation of Technical Specification 6.2.1.A.4.e (50-298/9625-01).

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c. Conclusion _q i

, The team conclud d that the Safety Review and Audit Board and the condition

j review group were effectively implementing license requirements. The team

, concluded that, except for the failure to review station operation to detect potential

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, nuclear safety hazards, the Station Operations Review Committee was implementing -

1 license requirements. Notwithstanding this failure, the team concluded that the

j review committees were effective in their oversight of licensee activities. .

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07 QUALITY ASSURANCEIN OPERATIONS

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07.1 Control of Open item Backloa

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a. Insoection Scope

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The team reviewed the operations backlog to determine the backlog size, the trend

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and how priorities were determined. The team also discussed these backlogs with

, applicable operations personnel.

b. Observations and Findinas

! The team noted that the operations department backlog was small(22 open items

, which included 5 procedural reviews and changes). The team's review found that

all of these items had been appropriately prioritized in terms of their safety

significance. As a result of these findings, the team determined that the operations

department were appropriately managing their open item backlog.

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c. Conclusions '

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The team concluded that the backlog of open items for operations were low and l

that the licensee was effectively managing the backlog. '

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07.2 Condition Report and Problem Identification Report Reviews

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a. Insoection Scoce i

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The team reviewed control room shift supervisor logs, condition reports, and

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problem identification reports to determhe the status of problem tracking and

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resolution. In addition, the team interviewed five operations personnel and the

operations manager.

b. Observations and Findinas

The team reviewed the control room shift supervisor logs for the months of

- September, October, and November of 1996 and noted that all incidents identified  :

in the logs were documented in problem identification reports. The team verified

that each of the problem identification reports clearly identified the issue and were

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reviewed and categorized (significant condition adverse t a quality, etc.) in j

accordance with the requirements set forth in Administrative Procedure 0.5, '

" Problem Identification and Resolution". The team selected ten of these problem

identification reports and verified that the assigned priority categories were

consistent with the safety significance of tha conditions identified.

The team also reviewed ten additional condition reports / problem identification

reports that had all actions completed. The team verified that these condition

reports / problem identification reports were reviewed and properly categorized. The l

team also verified that operability determinations associated with these condition I

reports / problem identification reports were properly dispositioned.

I For those condition / problem identification reports requiring a root-cause analysis,

the team reviewed the conclusions and the resultant recommended corrective

actions. The team found the licensee's analyses to be thorough and the

i recommended corrective actions to be appropriate. The team also verified that each

of the corrective actions were assigned a priority in accordance with Directive 4.12, ,

" Work Prioritization," and reviewed the completed corrective actions. As the result l

of these reviews, the team found the corrective actions to be properly closed. '

The team also reviewed 25 open problem identification reports assigned to

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operations for resolution and determined that each item had been appropriately

pricritized. No problems were noted from these reviews. In all cases reviewed, and

, as the result of operator interviews, the team determined that engineering support

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of the operations department was good. 1

c. Conclusions

The team concluded that operations was appropriately resolving emergent issues

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07.3 Operator Aids and Workarounds

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The team reviewed control room shift supervisor logs to determine the number,

status and use of operator aids and workarounds. In addition, the team interviewed

five operations personnel and the operations manager,

b. Observations and Findinas

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The team reviewed the licensee's operator aid and workaround programs. The

status of these programs, which were maintained in togs, was found to be current,

with each log identifying the number of outstanding items in the plant.

The team found that the licensee h'ad a total of 18 operator aids logged. The team

inspected 5 of these operator aids and found that they were appropriately reviewed

and approved. The team found that the licensee reviewed the operator aids log on

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a periodic basis. For those operator aids that were taken from the Technical

Specifications, piping and ir.strumentation drawings, and plant procedures, the team ,

!. verified that the latest revision of these documents were used. No unapproved  !

l operator aids were identified by the team and none of the operator aids were found j

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to constitute an operator workaround, j

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j' The operator workaround program was maraged by the operations shift supervisor

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assigned to the work control center. The team found that the licensee logged 14

items as workarounds. Operator Instruction 15, " Operator Workarounds," defined  !

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an operator workaround as any equiprnent, plant, training, policy, or procedure l

deficiency which, during normal, abnormal, or emergency conditions, would impede -!

l- effective operator response. The instruction also provided a scale that was used to I

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Of the 14 items listed, the licensee identified 5 that were assigned an A, B, or C l

l (high, medium, low ) priority, with only one considered to be a high (A) priority l

item. The other items, which did not impact plant operations, were not assigned a ,

priority in accordance with the operator instruction, prioritized workarounds were '

assigned an aging criteria (i.e., a cuggested time limit for item correction). The i

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team noted that four of the five prioritized items exceeded the recommended time

period listed in the operator instruction. The team also noted that the licensee  :

reviewed these workarounds and determined that the plant could be operated safely [

with these workarounds in-place until the next refueling outage. The team

considered management of operator workarounds to be appropriate.

c. Conclusions .

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The team concluded that the operator aids and operator workarounds were properly "

controlled.

07.4 Self-Assessment Activities j

a. Inspection Scoce . [

The team reviewed self-assessment activities in operations to determine the extent

of these activities.

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b. Observations and Findinas

The team found that the operations department had not performed a recent self

assessment. However, the team noted that operations personnel recently

implemented (only about 6 weeks prior to this inspection) individual operations

performance assessments. Operations personnel were required to fill out

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assessment forms of different areas on a periodic basis. At the end of the quarter, l'

the sheets were then compiled by operations management who put out a report

with the results. The team reviewed the first self-assessment report that was  !

issued. This report covered the November time period. The team considered the i

report to be a useful tool for identifying problems in operations. i

c. Conclusions

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While the team noted that there were no recent self assessments in operations, the j

team concluded that the newly implemented self-assessment program appeared ,

useful for identifying problems within the operations department. However, due to l

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the recent implementation of this program, the team could not assess the

effectiveness of the program.

II. MAINTENANCE

M7 QUALITY ASSURANCEIN MAINTENANCE ACTIVITIES

M7.1 Control of Open item Backloa

a. Inspection Scope

The team reviewed the maintenance backlog to determine the backlog size, the

trend (i.e., increesing, decreasing or steady), how the backlog was tracked and

managed, and how priorities were determined. The team also discussed the

backlog with applicable maintenance personnel. j

b. Observations and Findinas

To determine the maintenance backlog, the team requested a listing of all open

items assigned to the maintenance department that met the criteria for their {

backlog. The licensee provided approximately 120 items that they considered to be

part of their backlog. The team's review found that all of these items had been

appropriately prioritized in terms of their safety significance.

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The team found through interviews with maintenance planners that their workload

was significant with regard to the preparation of maintenance work requests and

responses to problem identification reports. Some planners indicated that this j

workload had an effect on the quality of their work activity. Maintenance planners i

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also indicated that the maintenance work request development process was a

cumbersome process which contributed to delays in the development of the

maintenance work requests.

The licensee recently hired contractors to assist with their backlog management

efforts to address the problems identified by the maintenance planners and to

address the potential backlog increase due to the upcoming refueling outage. The

team noted that the licensee formed a "Fix-It-Now" team. The team consisted of

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members from each department including a maintenance planner, an operator, craft

personnel, and engineers. The main purpose of this team was to address emergent

work, thus, allowing other plant personnel to concentrate on scheduled

maintenance activities.

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Another aspect of the Fix-It-Now team was to identify and implement process

improvementr, and to address backlogged maintenance work requests. The team

noted that this was a pilot program that was recently implemented and, therefore,

it~s effectiveness could not be determined at this time.

c. Conclusions l

The team concluded that the backlog of open items for maintenance was low and

that the licensee was effectively managing this backlog. However, the team noted

that with the advent of the upcoming refueling outage, problems with the

maintenance planning workloads and the cumbersome maintenance work request

process, were precursors to increased backlogs. The team also noted that the

licensee was taking action to preclude a backlog increase.

M7.2 Condition Report, Problem Identification Report and Maintenance Work Reauest

Reviews

a. Insoection Scope

The team reviewed maintenance condition reports, problem identification reports,

and work requests to determine the status of problem tracking and resolution. In

addition, the team interviewed five members of the maintenance planning group,

four maintenance craft personnel, and the maintenance manager.

b. Observations and Findinas

The team reviewed ten condition / problem identification reports that had all actions

completed. The team verified that these condition / problem identification reports

were reviewed and properly categorized. The team found the licensee's analyses to

be thorough and the recommended corrective actions to be appropriate. The team i

also verified that each of the corrective actions were assigned a priority in l

accordance with Management Directive 4.12, " Work Prioritization," and reviewed j

the completed corrective actions. As the result of these reviews, the corrective  !

actions for all but one condition report were found to be properly closed.

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A review of Condition Report 96-0604 indicated that the final corrective actions did

not appear to address, and in one case appeared to contradict, the recommended

corrective actions. The recommended corrective actions, from the root-cause

analyses, involved personnel training on prejob briefings and the use of a prejob

briefing form. The final corrective actions did not document that all recommended

training had been completed or if any had been performed. The contradiction

involved a memorandum issued to maintenance supervisors involving information

that was to be conveyed to work crew leaders. This memo stated that it was not

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expected that a formal briefing sheet or set routine be used on each job and that the

work crew leaders need only to review the work to be performed with their craft

personnel.

A discussion of this finding with the licensee personnelindicated that while the

package had not gone through its final review, they agreed that all the

reuommended corrective shouid be implemented. j

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The team also reviewed 25 open problem identification reports assigned to

maintenance for resolution, and determined that each item had been appropriately

prioritized. The team also reviewed six maintenance work requests which resulted

from priority one and two problem identification reports and were closed over the l

last 6 months. No problems were noted from these reviews. However, as the

result of these reviews, the team found that engineering support of maintenance

was inconsistent. Interviews with maintenance personnel indicated that

communication and cooperation with engineering was good as long as engineering

was not impacted by their own emergent issues. If engineering was impacted by

such issues, their communication and cooperation was not as effective.

c. Conclusions

The team concluded that while maintenance was resolving emergent issues, the l

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corrective action process needed improvements to assure that the proposed and

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completed corrective actions are consistent and fully resolved the problem.

M7.3 Ouality Assurance Audit

a. Insoection Scoce

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The team reviewed Quality Assurance Audit 96-15," Corrective Maintenance,"

which was performed during the period of October 18 through November 1,1996.

The team reviewed this audit and discussed the findings with licensee personnel to

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determine if the corrective actions that resulted from the audit were adequate and

completed in a timely manner.

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b. Observations and Findinas

This audit was found to be thorough and very critical of maintenance department

processes. Specifically, it noted that process inefficiencies, lack of a global

commitment to the schedule, and difficulty with intra-departmentalinterfaces made

the overall process ineffective. The ndit also identified a management failure to

encourage teamwork between departments. As a result of this audit, a number of

problem identification reports were issued by the licensee. Since this audit was l

recent (completed during this inspection), the licensee response to the audit was

not available. This audit review and interviews with quality assurance personnel,

further demonstrated that the quality assurance department was a0gressive in

identifying problem areas in the plant.

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c. Conclusions

The team concluded that the audit performed by quality assurance was thorough

and critical. The quality assurance department's aggressive efforts in identifying

licensee problems was notable.

Ill. ENGINEERING

E7 QUALITY ASSURANCEIN ENGINEERING ACTIVITIES

E7.1 Control of Open item Backloa

a. Insoection Scoce

The team reviewed the backlog in engineering to determine the backlog size, the

trend (i.e., increasing, decreasing or steady), how the backlog was tracked and

managed, and how priorities were determined. The team also discussed these

backlogs with applicable engineering personnel,

b. Observations and Findinos

The team requested the engineering backlog and noted that the licensee was not

readily able to provide this information. The licensee could not initially provide this

information, because the licensee's backlog was listed in at least six different data

bases. The licensee stated that the information listed in these data bases

collectively represented the enginuring open item backlog and current work. The

licensee listed the backlog as follows:

• Special Procedure completion reports 25

• Special test procedure completion reports 48

• Design change completion reports 136

• Engineering work / projects requests 474

• - Nuclear action item tracking items 936

• Drawing change notices 528

• Component evaluation packages 190

• Replacement component evaluation completion reports 141

• Maintenance work requests engineering review 267

• Maintenance work requests final engineering review 155

• Calculations with engineering judgments outstanding 145

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The team found that the backlog consisted of approximately 3000 items which the

team considered, based upon comparison with other single unit nuclear plants, to be ,

high. The team noted that the engineering work / projects requests had 8 priority

one items and 449 priority two items and the nuclear action item tracking system

had 9 priority one items and 115 priority two items. The licensee stated that all

engineering items were assigned priorities based on the corrective action program. ,

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The team reviewed the priority one items and concluded that they were not safety

significant. The team reviewed Administrative Procedure 0.15 "NPG Action item l

Tracking," which contained a list of items included in the nuclear action tracking

,

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system. These items were licensing documents, industry operating experience  ;

documents, corrective action program documents, and self assessments. The l

team's review found that all of these items had been appropriately prioritized in l

terms of their safety significance. The team noted that the licensee supplemented )

the engineering staff with contractors in an effort to reduce the backlog and that

there was a slight decrease in the backlog.

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c. Conclusions

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The team concluded that the engineering backlog of approximately 3040 items was

excessive. Although a slight decrease in the backlog number was acted, the team

was concerned that the engineering backlog was excessive.  !

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E7.2 Operability Determinations and Corrective Maintenance Work Orders f

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a. Inspection Scope

The team reviewed six operability determinations to determine the adequacy of l

engineering involvement and discussed these determinations with engineering  !

personnel. The team also reviewed 13 corrective maintenance work orders to j

determine the extent of engineering involvement. The team reviewed the work i

orders to determine the adequacy of the licensee's corrective actions for repetitive

equipment problems.

b. Observations and Findinas

The team found that the six operability determinations were adequate and had l

appropriate engineering involvement. In addition, the team found that the 13

corrective maintenance work requests provided adequate corrective actions for

repetitive equipment problems.

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c. Conclusions

The team concluded that engineering involvement with operability determinations

and maintenance work orders was appropriate and effective.

.

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E7.3 Temporary Modifications

a. Inspection Scope

The team reviewed all 25 of the temporary modifications that the licensee had

installed in the plant to determine the age of modifications, if the modifications were

marked on control room drawings and to determine if the 50.59 screening and

applicable safety evaluations were accomplished.

b. Observatlons and Findinos

The licensee tracks temporary modifications through the use of a log located in the

control room and maintained by operators. The team reviewed the temporary

modification packages and verified that they were complete. The packages

contained sufficient information to clearly identify the in-place modifications and

that applicable 10 CFR 50.59 reviews were performed. Plant drawings located in

the control room, affected by any of these temporary modifications, were labeled

with a temporary modification stamp. The operations personnelinterviewed by the

team were aware to consult the temporary modification log when a control room

drawing with a temporary modification stamp was encountered.

In addition, the team walked down five of these modifications and noted that they

were consistent with the modification package, and were properly labeled. The

team also performed a general walkdown of the facility and did not identify any

temporary modifications that were not already identified in the control room log.

The licensee's documentation indicated that 16 of these temporary modifications

were scheduled to be corrected and/or removed by the end of the next refueling

outage. The team concluded that the safety impact of the temporary modifications

on plant operations was minimal and that none of these modifications constituted

an operator workaround.

c. Conclusions

The team concluded that engineering processing of temporary modifications was

appropriate and effective.

E7.4 System Enoineerina

a. Insoection scope

The team interviewed three system engineers to determine their ability to handle  ;

their assigned workload and their ability to manage their time. l

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b. Observations and Findinos

The system engineers stated that approximately 50 percent of their time involved

emergent work. The engineers also stated that their remaining time involved

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witnessing surveillance tests. They indicated that they received good support from

design engineering. They also stated that while 25 percent of their time involved in-

plant activities, most of this time was used to resolve emergent issues. This lef t

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them very little time to be proactive toward identifying system problems.

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c. Conclusions

i

The team concluded that due to a high amount of emergent work, system engineers l

were restricted in their ability to proactively approach problems with their systems.

E7.5 Enaineerina Project Reauests

a a. Inspection Scope

The team reviewed two backlogged open engimering project requests and

interviewed the applicable engineers to detes. ,.ne the validity of the open status.

I

Engineering project requests were used to request engineering assistance or

evaluation for problems identified in the plant.

b. Observations and Findinas  !

The team found that one request was a system improvement that added a second

"

power source to the control room ventilation exhaust fan and, therefore, did not

impact plant safety or operation. The team also found that the other request, which j

, requested an engineering review of design piping analysis and hanger calculations

was not an operability concern.

j

c. Conclusions

The team concluded that engineering processing of the selected engineering project

requests was appropriate. The team also concluded that while these engineering

project requests were still open, this status did not impact plant operation and that

they were on track for closure.

E7.6 Enaineerina Disoosition of Problem Identification Reoorts

a. Inspection Scone

The team reviewed 45 problem identification reports (which included both open and

closed reports) and discussed a number of them with the applicable engineers to

determine if engineering had adequately dispositioned the reports and if the

engineering actions were timely. In addition, the team assessed the quality of the

root-cause evaluations and evaluated the adequacy of engineering involvement.

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b. Observations and Findinas

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During the review, the team noted that the licensee used design criteria documents

1

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to determine their design bases. The team noted that the licensee considered these i

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documents to be "living" documents and was maintaining the documents current.

The team challenged the design criteria document process, by requesting design

i information to assist with a system review, and noted that the licensee had little

difficulty retrieving the requested information. j

in general, the problern identification reports reviewed contained resolutions that

had proper engineering justification and proposed corrective actions that were

adequate to preclude recurrence of the problem. The team also noted through ,

interviews with licensee personnel that personnel were not hesitant to write

problem identification reports if issues were identified. Nevertheless, the team

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identified a problem identification report with a questionable engineering resolution.

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Problem identification Report 96-0509, dated May 20,1996, identified that the

emergency diesel generator cylinder exhaust differential temperatures exceeded the

licensee's 250'F differential temperature limit. The team determined that the

, licensee originally had a 100 F differential temperature limit which was considered

i an industry-accepted standard. Over time, the 1 censee had increased the

{ acceptable differential temperature limit because they were unable to maintain the

j original 100 F limit. In addition to the differential temperature increase, the

licensee also increased the cylinder maximum differential firing pressure from 75 psi

,

to 160 psi.

I .

The team noted that the accepted industry standard of 100 F maximum differential  !

j temperature and 75 psi differential pressure was based on maintaining an even

. power balance between cylinders. According to this standard, the cylinder balance

j was determined from the temperatures and pressures occurring in each cylinder and

! that cylinder temperatures should be within 100 F of the average while the cylinder

! firing pressures should be within 75 psi of each other. While the team was aware

that the licensee's emergency diesel generator vendor concurred with the present

operation, the team was concerned that the licensee, by continuing to raise the

temperature limit, was living with the problem rather than resolving the problem.

4 The team was also concerned that continued operation with such cylinder

- imbalances could result in diesel degradation.

I

This issue will be followed as an unresolved item pending further evaluation of the

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acceptability of increasing the emergency diesel generator cylinder exhaust

differential temperatures (50-298/9625-02).

c. Conclusions

]

The team concluded that engineering, in general, properly dispositioned plant

problems. However, the inspection identified an unresolved item involving the

,

acceptability of increased emergency diesel generator cylinder exhaust differential

i temperatures.

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E7.7 Self-Assessment Activities

a. Inspection Scoce

The team reviewed self-assessment activities in engineering. The team selected l

and reviewed portions of the licensee's engineering self assessment which was l

conducted February 5-23,1996. The team reviewed this self assessment to '

determine if the corrective actions identified from this self assessment were  ;

1 adequate and if the actions were completed in a timely manner. In addition, the i

team reviewed the licensee's engineering self-assessment followup, dated October ]

1996, which the licensee conducted to evaluate the effectiveness of the corrective

,

actions from the engineering self assessment. The team also interviewed i

engineering managers to determine the effectiveness of the corrective actions.

l

b. Observations and Findinas

1

. The team found that the licensee developed engineering department action plans to

process the corrective actions for the 36 items found during the engineering self

assessment. Since the licensee determined that the scope of work exceeded their

, resource capability, they decided to consider only the most important items first.

This reduced the scope of work to 12 items being actively resolved and 24 items l

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l being deferred. The team reviewed the list of 24 items that were deferred and

noted that unauthorized modifications, operability ac3essments/50.59s, plant design

and configuration control, accessibility of design basis information, and procedural

compliance and attention to detail were included as part of the 24 items deferred. ,

l

As a result of an NRC violation (NRC !nspection Report 50-298/96-04),regarding a i

modification being performed using a maintenance work request instead of the  ;

design process, the licensee initiated corrective actions to examine additional work l

activitiem The licensee sampled 10 percent of the existing 21,000 maintenance

work requests and found that 128 were unauthorized modifications. The licensee

stated that they evaluated them for operability by walkdowns and review of

. documentation and found no safety concerns. Since 128 out of the 2100 reviewed

were unauthorized modifications, the licensee committed to the NRC to review the

! remainder of the maintenance work requests by December 31,1997 and to

disposition all identified unauthorized modifications by June 30,1998. At the time

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this inspection, the licensee identified a total of 350 unauthorized modifications.

The team reviewed nine of the unauthorized modifications and found no safety

concerns. The teem noted that the self assessment found that there was no

process to ensure that these unauthorized modifications were evaluated for  ;

acceptability of the design as is, that the design inputs were not invalidated and i

that configuration control was maintained. Based upon this review by the team and

discussions with licensee personnel, the licensee expanded their 12 item list to

13 items to include unauthorized modifiq,ations.

The licensee also provided interoffice Correspondence K0960050, dated

December 3,1996, concerning the licensee's engineering acti,on plans. This

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correspondence addressed the implementation of the 36 items. The team noted

that the list was increased to 14 items which were listed as "must do" items.

These items included; integrated planning and scheduling between engineering and

plant organizations, system engineering problems, plant configuration control and

design basis, improving the efficiency of engineering processes and procedures,

reducing backlog, outage maintenance work plan, procedure programs for the

outage, refueling outage engineering contract preparation, outage modifications, l

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Appendix R program validation, training and certification, improved technical  !

specifications, nonoutage task modification and task action plan, and formation of l

an unauthorized modifications focus group. The team noted that some of these  !

I

items were not included on the former list of 13 action items. The team found that

this was due to the fact that some of the other items were either deferred, included

as part of another item, or closed out. The team concluded that the licensee's

actions were acceptable. I

The licensee's engineering manager stated that these action items and theii large

4

engineering backlog (discussed in Section E7.1) had a severe impact on available

resources. Furthermore, he stated that recent management changes (including the

'

l engineering manager), staffing levels, industry evaluation teams, and NRC i

inspection teams, impacted the licensee's ability to cope with their workload. The

team noted that the licensee's engineering staffing was 209 engineers which

included 109 on-staff engineers and approximately 100 contract engineers.

!

The team also reviewed the engineering self-assessment followup, dated October

1996. The team found that the followup assessment determined that while there

was some progress in improving engineering effectiveness to perform routine and

emergent site activities including the identification and resolution of technical

issues, overall progress was poor.

The followup team noted that there was a concern in the engineering organization

regarding the commitment of management, the availability of resources, and the

authority of the plan owners to implement the action plans effectively. The

followup team also concluded that the engineering workload appeared to exceed the

available resources and that system engineering performance did not meet

expectations due to the volume of emergent work that prevented the system

engineers from performing their primary responsibilities. The licensee's followup

team concluded that, although the engineering self assessment had been effective

in the identification of performance problems, engineering had not been effective ir

resolving the identified problems.

The NRC inspection team noted that the licensee's initial self assessment and

followup self assessment were very critical of the engineering organization. The

self-assessment findings were consistent with the team's findings. The team

concluded that the self assessment was very effective toward identifying problems

within the engineering organization.

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c. Conclusions

The licensee's engineering self assessment and self-assessment followup were

thorough and comprehensive which resulted in many good findings. The self-

assessment findings were found to be consistent with those identified by the NRC

inspection team. The current NRC inspection did not identify any issues that were

net already identified in the self-assessn'ent report. The licensee's followup self

assessment found that engineering had not been effective in resolving the findings

of the first self assessment.

E7.8 Quality Assurance Audit

a. Insoection Scoce

The team reviewed Quality Assurance Audit 96-07, " Design Control," that was

performed during the period of May 3-22,1996. The team reviewed this audit and

discussed the findings with licensee personnel to determine if the corrective actions

that resulted from the audit were adequate and completed in a timely manner.

b. Observations and Findinas

The team noted that the audit was thorough and had good findings. The findings

included a determination that the design control processes were inadequate, that

design engineers did not have a uniform understanding of processes and

procedures, and that maintenance of the Updated Safety Analysis Report was

inadequate. The licensee's audit team concluded that when there were deficiencies

associated with the Updated Safety Analysis Report, there was no consolidated,

formal, effective corrective action effort or plan in place to resolve these

deficiencies.

The team also reviewed the engineering response to this audit. The team noted

that engineering agreed that the audit raised valid issues and commended the

quality assurance audit team on a high value added audit. The team reviewed the  ;

engineering recommended corrective actions, developed in response to this audit, l

and found them acceptable.

The team noted that the Updated Safety Analysis Report issues were directed to the

licensing organization. A review of the licensing response indicated that licensing

did not agree with the audit findings. Specifically, licensing reviewed the audit j

findings and concluded that maintenance of the Updated Safety Analysis Report I

was adequate and that no further corrective actions were necessary. In response to

this position, the quality assurance department documented their disagreement in

Letter QAD960256, dated August 30,1996. The purpose of this letter was to

escahte the issue for consideration of additional resolution actions. The licensee

informed the team that this issue was still being resolved and that they planned to

address this issue when they responded to the NRC issued letter regarding

compliance with NRC regulation .10 CFR 50.54 (f) that addressed discrepancies

between the Updated Safety Analysis Report and the as-built plant configuration.

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c. Conclusions

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The team concluded that the audit performed by quality assurance was thorough

and critical. The audit identified issues similar to the issues identified by the team.

The quality assurance department was aggressively pursuing resolution of its

findings.

E7.9 Operatina Experience Feedback  :

a. Insoection Scope  ;

l The team evaluated the effectiveness of the licensee's operating experience

, feedback program by reviewing the program and interviewing five system engineers.

l The team reviewed Administrative Procedure 0.10, " Operating Experience

Program," and Cooper Nuclear Station Operations Experience Review Desktop i

Guide 5, " Guideline for the Communication of Industry Operating Experience to

i CNS." ' '. also reviewed the licensee's activities on the following five recent

j indust 5 a. .a determine the licensee's effectiveness in implementing this

2

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• The lubricating oil fire which occurred at Arkansas Nuclear One, Unit One, on

October 16,1996;

!

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• General Electric Service information Letter 604, " Reactor Water Clean-Up  !

l System Break Detection", i

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l * Licensee Event Report 95-013 for the Duane Arnold nuclear plant, j

j concerning the potential for water hammer in the high pressure coolant 1

injection turbine exhaust pipe;

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• An industry event which occurred in October 1996, concerning potential

i standby liquid control system problems at the Hope Creek nuclear plant due

to operating procedures not specifying a maximum system temperature; and,

s

• General Electric Service Information Letter 603, which documented that the

i net-positive suction head calculations for low pressure emergency core

cooling systems were not consistent with plant licensing bases,

b. Observations and Findinas

The team noted that the licensee's procedures directed that the Operating

l Experience Review staff review information provided from the NRC and from the

industry regarding plant events on a daily basis. The procedures also directed that

events be reviewed by the responsible system engineer for applicability and for the

initiation of problem identification and corrective action documentation.

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For the selected plant events, the team found that the licensee assigned followup

{ - responsibility, properly identified applicability to the Cooper Nuclear Station and

initiated appropriate corrective actions when applicable.

The team noted that while the licensee's actions for the reactor water cleanup .

system break detection and for the standby liquid control system high operating

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temperature were not complete, their evaluation was ongoing and the completion

was appropriately scheduled.

I

c. Conclusions

The team concluded that the licensee's operating experience review program was

effective in identifying, determining applicability, tracking, and responding to both

NRC and industry events. )

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.E8 MISCELLANEOUS ENGINEERING ISSUES

a. -Insoection Scope

l

The team conducted a followup of activities that were performed as the result of a

safety system functionalinspection of the emergency electrical system and auxiliary

support systems conducted during the period of May 11 through June 19,1987.

The purpose. of the followup activity was to determine if the corrective' actions

developed to resolve issues during the safety system functionalinspection were

.

treated generically to address similar potential problems with other plant systems.

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The team's followup activities involved addressing specific items identified in the

safety system functionalinspection. These activities were accomplished using

personnel interviews and record reviews.  !

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b. Observations and Findinas

The safety system functionalinspection review of the service water system

identified deficiencies involving the measurement of heat removal capabilities and

te, sung to assure that essential components receive required flows. This inspection

reviewed the reactor equipment cooling, fuel pool cooling, and turbine equipment

cooling systems to deterrnine if the lessons-learned from the service water system

were implemented, as appropriate, for these systems.

Measurement of Heat Removal Capabilities (item 8710-01)

The licensee uses Procedures 13.15.1," Reactor Equipment Cooling Heat Exchanger

Performance Analysis," and 13.16.1," Turbine Equipment Cooling Heat Exchanger

Performance Analysis," to measure the heat removal capabilities of the system heat

exchangers. The team reviewed these procedures and the test results from the last

heat exchanger heat removal tests. No problems were identified with the

procedures or the test results.

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e

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The team also determined that the licensee does not measure the heat removal I

capabilities of the fuel pool cooling system. The team discussed this observation i

with the system engineer and was informed that since the fuel pool cooling system j

'

uses chemically controlled water on both sides of the heat exchanger, that fouling

was not considered to be a problem. The engineer further stated that they never ,

experienced any fouling problems with these heat exchangers. -

Testing for Adequate System Flows (ltem 8710-02)

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The licensee uses Procedure 6.2 REC.102," REC Critical Subsystem Emergency .  !

, Mode Flow Test," during a refueling outage to verify that the reactor equipment I'

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cooling system flow is adequate during system emergency operations. The licensee

'

alco uses Procedure 6.1 REC.101," REC Surveillance Operation," to perform monthly

i or quartarly flow tests of the reactor equipment cooling pumps. The team reviewed i

these procedures and the completed data from these procedures and verified that '

the appropriate system flows were obtained. No problems were identified with

,

either the procedures or the completed flow data.

The team was informed that flow testing is not performed for either the turbine

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equipment cooling or the fuel pool cooling systems. The team noted that these

systems are not used for accident mitigation and did not affect the plant's risk

2

profile, i

Adequacy of Operator Training for Casualty Responses (Item 8710-03) j

The team reviewed current emergency operating procadures for the reactor j

! equipment cooling system and abnormal operating procedures for the turbine

equipment cooling and the fuel pool cooling systems. In addition, the team

discussed the use of these procedures with operations personnel. As the result of

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these reviews and discussions, the team determined that the procedures adequately i

addressed casualty conditions for these systems.

l The team also reviewed training lesson plans for these systems and discussed

training activities with licensee personnel. Plant training has changed significantly

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since 1987 with implementation of detailed training plans and the addition of the

, plant simulator in 1990. Based upon this review and discussions, the team

determined that operator training and guidance was adequately addressing system

casualty responses.

i Service Water System Flow Testing (Item 8710-04)

i

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As the result of the Safety System FunctionalInspection, the licensee conducted a ,

special test of the service water system in accordance with Special Test l

Procedure 87 011," Post-LOCA Service Water System Flow Test," on May 21 and  ;

i

May 25-26,1988. This test was performed to verify that the service water was '

, capable of meeting the post-LOCA flow rates. The results of this test were

l reviewed'by the NRC as documented in NRC Inspection Report 50-298/89-03.

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During this inspection, the team verified that periodic surveillance

Procedure 6.SW.102, " Service Water System Post-LOCA Flow Verification," was

developed and implemented to periodically verify that the post-LOCA flow rates

were still adequate. The team also reviewed the completed surveillance conducted

on December 24,1995, and found the test results to be satisfactory.

Normal Power Transformer Sizing (item 8710-05)

The Safety System FunctionalInspection addressed the sizing of the startup and

emergency power transformers, but did not address the sizing of the normal power

transformers. During discussions with licensee engineers, the team was informed

that the normal transformers were not used for accident events and, as a result, did

not power emergency core cooling system components. The team also reviewed

electrical drawings and the NRC electrical distribution system functional inspection

(NRC Inspection Report 50-298/91-02) conducted in July 15 through August 16,

1991. This report documented that the normal transformers were properly sized for j

their application. I

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Adequacy of the DC Power System (item 8710-06)

The safety system functionalinspection did not address the adequacy of the

de power system. Review of this issue by the team indicated that the licensee

demonstrated that the dc power system was adequate based on a dc voltage drop

study and a de load study performed by their vendor and documented in licensee ,

letters dated August 14 and November 23,1987. These studies, which I

demonstrated that the de power system was adequate, was reviewed by the

licensee's engineering department and confirmed to be adequate. The team also

reviewed the electrical distribution system functional inspection (NRC Inspection

Report 50-298/91-02)that was conducted in 1991. These studies were reviewed '

during this inspection. The results of this review supported the licensee's findings.

Sizing of the 240V AC Power System (Item 8710-08)

Since the Safety System Functional Inspection did not address the sizing of the

240V ac power system, there was a concern that this system was not reviewed for

proper sizing. The team followed up on this concern by reviewing the AC critical

buses one-line diagram, conducting discussions with the applicable engineer, and

review of the electrical distribution system functional inspection (NRC Inspection

Report 50-298/91-02)that was conducted in 1991. Based upon this review, the

teare concluded that there is no 240V ac system used at the Cooper Nuclear

Station.

480V AC Switchgear Sizing (Item 8710-09)

Since the Safety System Functional inspection did not address the sizing of the

480V ac power system, there was a concern that this system was not reviewed for

proper sizing. The team reviewed the electrical distribution system functional

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inspection (NRC Inspection Report 50-298/91-02)that was conducted in 1991.

This 1991 inspection verified that the 480 Vac switchgear was properly sized.

Equipment Performance Trending (Item 8710-13)

The safety system functional inspection identified that the service water system did

not have an adequate trending program as evidenced by the fact that some pumps

were operating in the " ALERT" range. This issue was resolved by issuance of a

revised service water pump procedure.

.

There was a concern that other systems, such as the reactor equipment cooling, I

turbine equipment cooling, and the fuel pool cooling systems may also lack a I

trending program. The team reviewed tho equipment trending program (which  !

included the trending curves and procedures) and the discussed the program with

the assigned engineer. From this review, the team determined that trending was

being performed on the pumps for the three listed systems. The team also

determined that trending was being conducted on all safety-related system pumps )

and on a limited extent on the nonsafety-related equipment. l

c. Conclusions

The team concluded that the issues identified in the 1987 safety system functional  !

inspection for specific systems and components were properly addressed on a

generic level for other in-plant systems.

IV. Plant SuppoE

F8 MISCELLANEOUS FIRE PROTECTION ISSUES

a. Inspection Scope

The team toured the plant, reviewed the licensee's 10 CFR, Appendix R, Safe and

Alternate Shutdown Report, reviewed Safe Shutdown Procedure 5.4.3.2, " Post-Fire

Shutdown to Cold Shutdown Outside Control Room," and interviewed licensee

personnel. In addition, the team conducted a review of the licensee's actions for

fire protection issues identified in Licensee Event Reports96-006 and 96-009.

b. Observations and Findinas

Licensee Event Report 94-016, Supplement 1

As part of the corrective actions for Licensee Event Report 94-016, Supplement 1,

which identified that the control power for Emergency Diesel Generator 2 did not

meet the fire protection requirements of 10 CFR Part 50, Appendix R, the licensee

conducted a re-evaluation of the Cooper Nuclear Station's Safe and Alternate

l

.

Shutdown Analysis Report. As a result of this re-evaluation, the licensee

documented in Licensee Event Report 96-006, issued on June 6,1996, that safe

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shutdown deficiencies potentially existed which were contrary to the requirements

of 10 CFR Part 50, Appendix R.

Licensee Event Report 96-006

Licensee Event Report 96-006 documented that these discrepancies involved

control power for Reactor Equipment Coo!!ng Pumps 1C and 1D, the high pressure

safety injection room cooler f an control relays, and an inappropriate installation of a

test jack in the control circuitry of Motor-Operated Valve HPCI-MOV-M058. The

conclusions documented in the licensee event report were that these issues were of

minor safety significance because the emergency operating procedures provided

coping strategies and that the test jack installed in the control circuitry of

valve HPCI-MOV-M058 did not affect the ability of the plant to achieve and

maintain hot shutdown.

The team verified through procedure review that the licensee could cope with the

control power problems identified in this licensee event report. While the recovery

from these failures were not in Procedure 5.4.3.2, the operators were trained to

deal with these vulnerabilities. The team concluded that these deficiencies did not

constitute a violation of 10 CFR Part 50 Appendix R, Section Ill G.

Licensee Event Report 96-009

On July 25,1996, the licensee again reported to the NRC, that as a result of their

Appendix R re-evaluation, they identified additiorial items which did not have

acceptable Appendix R coping strategies. These items, which were reported in

Licensee Event Report 96-009, included:

1

• Fire-induced ground faults at multiple locations which could cause the failure

of the reactor core isolation cooling pump control power fuses. This failure

would prevent the reactor core isolation cooling pump turbine from

exceeding idle speed.

• Fire-induced ground faults at multiple locations which could cause failure of

control power fuses for Emergency Diesel Generator 2. If the failure

occurred prior to diesel generator isolation for alternate shutdown, the failure

could make this diesel generator unavailable.

• Fire-induced ground faults at multiple locations that caused the control

circuits for Circuit Breaker 1GE (the tie-circuit breaker for Emergency Diesel

Generator 2) and Circuit Breaker 1GS (the emergency transformer circuit

breaker) to be damaged, thereby, preventing closure. This would cause

Emergency Diesel Generator 2 to be unavailable and prevent the shutdown

bus from being energized.

.

23

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A failure to analyze the initiation logic for the automatic depressurization

system for potential spurious operation. A fire-induced short circuit could

cause the automatic depressurization system valves to fail to close following

initiation.

A failure to analyze for the potential of the control building emergency

ventilation dampers (HV-PNL-ECBH1 and HV-PN-ECBHil) to spuriously close

due to a fire-induced hot short.

• A failure to analyze for the potential for spurious operation of reactor

equipment cooling pump discharge valves (REC-MO-713 and REC-MO-712)

due to a fire-induced hot short. This spurious operation could cause a run

out condition for the reactor equipment cooling pumps and result in pump

damage.

• A failure to analyze for potential fire-induced spurious operation of residual

heat removal valves (RHR-MO-25A,25B,27A, and 27B) due to a hot short.

Spurious opening of these valves could place the unit in an unanalyzed

operating mode with the residual heat removal system operating concurrently

in the suppression pool cooling mode and the low pressure coolant injection

mode.

• A failure to identify that manual actions were needed to re-open service

water outlet valves (SW-MOV-89A and SW-MOV-898) for the residual heat

removal heat exchangers if fire-induced ground faults at multiple locations

caused a loss of remote positioning capability.

The team reviewed the licensee's actions to correct the identified deficiencies. The

first two deficiencies, involving the reactor core isolation cooling and the Emergency

Diesel Generator 2 control power fuses were corrected with plant modifications.

The team verified that Modification Packages MP 96-112,"RCIC Appendix R

Modifications," and MP 96-113," Diesel Generator #2 Appendix R Modifications,"

corrected these ground fault deficiencies.

The remaining deficiencies were corrected with revisions to Procedure 5.4.3.2. The

team reviewed these revisions and verified that the revised procedure provided

sufficient instructions to allow the operators to mitigate any problems caused by the

ground faults or hot shorts. The team noted that the licensee's corrective actions

were prompt and effective.

On April 17,1996 the NRC issued a Severity Level lli violation (EA 96-094) for the

Appendix R discrepancies identified in Licensee Event Report 94-16 as documented

in NRC Inspection Report 50-298/96-08. The team's review of the discrepancies

identified in Licensee Event Reports96-006 and 96-009 indicated that:

• These new discrepancies were identified by the licensee as part of its l

corrective action for EA 96-094 and reported in licensee event reports; j

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• The root cause involved an inadequate Appendix R evaluation which I

was identical to the violation documented in NRC Inspection

Report 50-298/96-08;

These new discrepancies also involved the effects of fire induced ground

faults and hot shorts and therefore did not change the safety significance of

the regulatory concern; and,

The licensee's corrective actions appear to be prompt and comprehensive. ,

I

This licensee-identified and corrected violation is being treated as a noncited

violation, consistent with Section Vll.B.4 of the " General Statement of Policy and

Procedures for NRC Enforcement Actions," NUREG-1600 (50-298/9625-03).

Alternate Safe Shutdown using Automatic Depressurization and Core Spray

Systems l

l

During the review of the licensee's Safe and Alternate Safe Shutdown Analysis l

Report, the team noted that the licensee was using an alternate shutdown method  ;

in lieu of the normal shutdown method to cover and cool the reactor core for some i

post-fire safe shutdown scenarios. Specifically, the automatic depressurization

system was being used to depressurize the reactor vessel and the core spray

system was being used to cover and cool the reactor core.

10 CFR Part 50 Appendix R, Section Ill.L.2 establishes the performance goals for

safe shutdown functions. Section Ill.L.2.b. specifies that the reactor coolant l

makeup function shall be capable of maintaining the reactor core coolant levels l

above the top of the core for boiling water reactors. During an NRC inspection  ;

conducted April 21-25,1986 (NRC Inspection Report 50-298/86-15),the NRC i

identified that if depressurization is begun within 6 minutes after rod insertion with

the water level at normal operating level the level would not go below the top of ,

active fuel. The inspection found that this was not consistent with the reactor i

safety considerations used in the development of the emergency operating

procedures. The emergency operating procedures in use at that time prescribed the

use of the automatic depressurization/ core spray system method only when other

methods were not available and the water level was at the top of the active fuel.

This 1986 inspection concluded that the licensee's analysis was not complete and

that the analysis should consider the top of active fuel as the starting point for the

alternate safe shutdown scenarios. In addition, the report concluded that the re-

analysis would probably result in partial core uncovery, and that this condition

would require are exemption from the technical requirements of Appendix R. This

was considered to be an unresolved item.

In a subsequent NRC inspection conducted January 26-29,1987 (NRC inspection

Report 50-298/87-04),the NRC reviewed the licensee's re-analysis and concluded

that the core would be uncovered. This inspection found the licensees core

uncovery re-analysis satisf actory and, based on this finding, closed the unresolved

25

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item. However, this closure action did not relieve the need for the licensee to

request an exemption from the Appendix R requirements.

While the team noted that the licensee's re-analysis indicated that an exemption

from the technical requirements of Appendix R was required, no exemption was

requested.

1

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This issue will be discussed with the NRR program office for further review and

analysis of the altemate safe shutdown method using the automatic

depressurization and core spray systems. This issue is considered to be unresolved

pending the results of this review and analysis (50-298/9625-04).

Fire Detection System Capability

i

During plant tours, the team observed an apparent lack of area-wide fire detection m

the plant. In addition, the team noted that the placement, spacing, and application

of fire detection devices did not satisfy industry fire protection engineering

practices.

The team reviewed the Cooper Nuclear Station, Design Criteria Document 11, Fire l

Protection. Section 5.1 of this document, " Fire Detection and Alarm System," j

Subsection 5.1.3, " Performance Requirements, Criteria, and Basis," Item I, specified )

that the fire protection systems and related equipment shall be designed in  !

accordance with the National Fire Protection Association standards. The licensee l

was unable to provide an engineering evaluation or the National Fire Protection i

Association code of record.

Based upon the design criteria document review, the team noted that for the type of

heat detectors used at the plant, the manufacturer recommended a maximum area

coverage (spacing) under ideal conditions (smooth ceilings with ceiling heights

below that of the UL tested conditions) of 2500 square feet. Since the conditions

at Cooper Nuclear Station were not ideal in that several plant areas existed where

the ceiling was subdivided by beams that created irregular deep beam pockets,

closer spacing of the detectors were required to achieve a responsive warning to a

fire.

In addition, the team noted that the spacing of the smoke (ionization) detectors in

the reactor building was not consistent with the manufacturers recommended

spacing. The maximum recommended spacing was 30 feet (area coverage 900 )

square feet) on a 15 feet 9-inch high smooth ceiling with no air movement and no

'

physical obstructions between the fire source and the detector. With conditions

other than these, the manufacturer recommended the application of engineering

judgement for detector location and spacing. The team observed that generally only

four smoke detectors were located on each elevation of the reactor building. Since

the observed plant configurctions, which included high ceilings, physical

obstructions, and air flow, were different than the ideal conditions, the detector

spacing had to be reduced. The licensee's present fire detector installations appear

to be inconsistent with industry fire protection engineering standards.

26

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.

The team noted that the licensee had not performed a detailed design / code

evaluation of the fire detection system to demonstrate that the fire detection system

would rapidly detect an incipient fire. The licensee did inform the team, however,

that they implemented an Appendix R program validation project plan to evaluate

the adequacy of the fire detection system for Appendix R compliance.

This issue will he discussed with the NRR program office for further review and

analysis of the adequacy of the fire detection system. This issue is considered to

be unresolved pending the results of this review and analysis (50-298/9625-05).

Recirculation Pumo Motor-Generator Set Fire Protection

The Cooper Nuclear Station has two reactor recirculation pump motor-generator

sets located on elevation 958'-0" of the reactor building. Due to the presence of

1500 gallons of oilin each of these units, the motor-generator sets are considered a

major fire hazard and represent a significant fire control and mitigation challenge

that could affect safety-related plant areas.

The team conducted a walkdown of this area and noted that the motor-generator

sets were protected by a pre-action automatic sprinkler system. However, this

system did not appear to be designed in accordance with the applicable National

Fire Protection Association codes. The team noted that the system used reduced

flow orifice type sprinkler heads that did not provide complete coverage throughout

the area. For example, the team observed that sprinkler protection was not

provided under significant obstructions created by duct work. The team also noted

that it appeared that activation of an excessive number of reduced orifice sprinkler

heads were required in order to supply the necessary water to mitigate a

combustible liquid fire.

The team also observed that the overall fire protection design for this area did not

consider smoke propagation or have adequate curbing to collect the potential oil

spillage during a motor generator fire. As a result, smoke from a motor-generator

set tube oil fire could fill the refueling floor area and inadequate curbing could allow

burning oil to flow through the equipment hatch to lower levels of the reactor  ;

building.

1

This issue will be discussed with the NRR program office for further review and j

analysis of the adequacy of the recirculation pump motor generator set fire j

suppression system. This issue is considered to be unresolved pending the results

of this review and analysis (50-298/9625-06).

,

Control of Combustible Material

l

l During a plant tour on November 20,1996, to inspect combustible material

l controls, the team observed three instances where small quantities of transient

'

combustible materials were lef t in the reactor building after the end of the work

shif t. The team noted that paragraph 8.1.11.1 of Procedure 0.7.1, " Control of

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Combustibles," required that all unnecessary combustible materials be removed or

properly stored and that the area be cleared at the end of each work shift.

The team also noted that Quality Assurance Audit 96-08, conducted in July 1996,

identified weaknesses with the control of combustible materials. One of the

corrective actions from this audit was to revise Procedure 0.7.1 to clarify

combustible control requirements and to provide training on this procedure.

Procedure 0.7.1 was revised to clarify the transient combustible control

requirements; however, the training was not completed. In the interim, the

corrective action was to conduct continuing plant walkdowns to check that

transient combustible material controls were being followed.

10 CFR Part 50, Appendix B, Criterion XVI, requires that measures shall be

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

corrected. In the case of significant conditions adverse to quality, the measures

shall ensure that .ne cause of the condition is determined and corrective action

taken to preclude repetition. The licensee's failure to implement adequate corrective ,

action for the control of transient combustibles is a violation of 10 CFR Part 50, 1

Appendix B, Criterion XVI (50-298/9625-07).

c. Conclusions

The team concluded that the licensee has been taking prompt and effective

corrective actions to resolve deficiencies identified by their on-going Appendix R

compliance re evaluation program. The failure to take adequate corrective actions

for controlling transient combustible materials was considered to be a violation

involving an inadequate corrective action.

Three unresolved items requiring resolution by the NRR program office were

identified. These items involved the use of the automatic depressurization system

and the core spray system as an alternate safe shutdown method, the adequacy of

the fire detection system, and the adequacy of the fire suppression system in the

reactor recirculation pump motor generator sets.

V. MANAGEMENT MEETINGS .

X1 EXIT MEETING SUMMARY

The team presented the inspection resu!ts to members of licensee management at

the conclusion of the inspection on December 13,1996. The licensee

acknowledged the findings presented.

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

were proprietary. No proprietary information was identified.

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ATTACHMENT 1

PARTIAL LIST OF PERSONS CONTACTED

Licensee

L. Bergen, Senior Manager, Safety Assessment / Site Support

M. Boyce, Engineering Manager

D. Buman, Design Engineering Manager

J. Dillich, Maintenance Manager

F. Diya, Acting Engineering Support Manager

R. Gardner, Operations Manager

M. Gillan, Corrective Action Program Supervisor

R. Godley, Plant Engineering Manager

P. Graham, Vice-President, Nuclear

B. Houston, Manager, Nuclear Licensing

J. Lechner, Senior Staff Engineer, Fire Protection

J. Long, Manager, Events Analysis

M. Peckham, Plant Manager

J. Pelletier, Senior Manager, Engineering

D. Reeves, Senior Staff Engineer, Operating Experience Review

M. Spencer, Engineering Programs Supervisor

B. Toline, Quality Assurance Manager

M. Unruh, Maintenance Planning Supervisor

R. Wenzl, Operations Support Engineering Supervisor

INSPECTION PROCEDURES USED

IP40500 Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing

Problems

IP92903 Followup - Engineering

IP92700 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

Facilities

ITEMS OPENED AND CLOSED

Opened

50-298/9625-01 VIO Failure of the Station Operations Review Committee to review

station operations so that potential safety hazards could be

detected.

50-298/9625-02 URI Acceptability of the emergency diesel generator cylinder

differential temperatures.

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50-298/9625-03 NCV Eight examples of the failure to implement the requirements of ;

10 CFR Part 50, Appendix R involving fire induced ground  ;

faults and hot short circuits.

50-238/9625-04 URI Adequacy of the alternate safe shutdown method for a fire.

!

50-298/9625-05 URI Adequacy of the fire detection system.

50-298/9625-06 URI Adequacy of the fire suppression system in the reactor

recirculation pump motor-generator area.

50-298/9625-07 VIO Failure to identify and correct transient combustible control

problems.

Closed

50-298/9625-03 NCV Eight examples of the failure to implement the requirements of

10 CFR Part 50, Appendix R involving fire induced ground

faults and hot short circuits.

LIST OF DOCUMENTS REVIEWED

Plant Procedures

Procedure Revision Title

No.

2.2.65 33 Reactor Equipment Cooling Water System

2.2.65.1 9.2 REC Operations .

2.2.66 38 Reactor Water Cleanup

2.4.8.1 12.2 TEC System Failure - Loss of Pumps 1

2.4.8.6 12 Fuel Pool Cooling System Failure j

!

3.4.5 O Engineering Evaluations i

3.9 10C1 ASME Code Testing of Pumps and Valves 4

5.2.4 10 Loss of All Reactor Equipment Cooling Water l

5.4.3.2 13 Post-Fire Shutdown to Cold Shutdown Outside Control Room l

7.0.1.7 O Troubleshooting Plant Equipment i

13.15.1 5&6 Reactor Equipment Cooling Heat Exchanger Performance

Analysis

13.16.1 2C1 & 2C2 Turbine Equipment Cooling Heat Exchanger Performance

Analysis

6.SW.102 1.1 Service Water system Post-LOCA Flow Verification

6.2 REC.102 O REC Critical Subsystem Emergency Mode Flow Test (Div 2)

6.1 REC.101 2 REC Surveillance Operation

6.1 REC.102 O REC Critical Subsystem Emergency Mode Flow Test (Div 1)

STP 87-011 4 Post-LOCA Service Water System Flow Test

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4

0.7.1 6 Control of Combustibles

0.5 8 Problem identification and Resolution

0.10 2.1 Operating Experience Program

0.15 9 NPG Action item Tracking

Dir. 4.12 1 Work Prioritization

lostr.14 0 Operations Performance Assessment

Instr.15 0 Operator Workaround=

Design Changes (DC) and Modification Packages (MP)

No. Title

DC 88-201C HPCI Room Cooling Modification

DC 92-109 Alternative Shutdown Hot-Short Modification

DC 93-057 SW and REC System Modifications

MP 96-112 RCIC Appendix R Modifications .

MP 96-113 Diesel Generator #2 Appendix R Modifications

l

Temporary Modifications l

4

No. Title j

94-11 MPF EFF Rad Monitor sample flow control valve, RMV-MOV-431MV

94-20 Install gauges on Gland Steam Exhaust line annulars

94-21 Install gauges on MS Bypass Valve Exhaust line annulars  ;

94-23

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Caps on Drains No.6 and No.7 in the reactor building

94-32 To install and document metal sampler in Main Condensate System

94-37 No.1 DG Exhaust Muffler Bypass Valve doesn't have 4 bolts

95-14 Move Westinghouse Office to south end of Turbine building

95-38 MS-V-186 MSL C Vent in steam tunnel

95-40 Seal Weld Union te RCIC-LS-74

96-01 MS-ADV-DRV4 Gv i outlet drain inlet flange

96-02 Low pressure turbine No.2 Intercept Valve No.4 downstream flange

96-04 T-932-HP Turbine. Right top side of HP Turbine, GV No.2 inlet flange

96-07 Fire system No.2. Disconnect HAD C from loop

96-14 Appendix R criteria on HPCI-MO-58. Lift leads to ensure valve will perform

under Appendix R conditions

96-15 Main Turbine Stop Valve No.1 has steam leak. Leak repair flange and

sealant

96-18 MS-LS-101. Bolt to hold down the instrument cover broke off

96-20 A RRMG positioner internal electrical stop jumpered out. Extra stop not

required ,

96-21 B RRMG positioner internal electrical stop jumpered out. Extra stop not

required

96-22 C phase main power transformer alarm. Lifted laad for low oil level and relief

.

valve

96-23 DG-AOV-MB2 Replacement valve installed

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96-24 A Air Compressor moisture separator outlet trap. Install Tee and extra drain

, line and valve I

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96-26 Temporary repairs to the discharge piping of the fire system jockey pump

96-27 No.1 DG Muffler Bypass /DGSA-PRV-7. Fails open the muffler bypass valve

'

2

96-28 No.2 DG Muffler Bypass /DGSA-PRV-8. Fails open the muffler bypass valve

! Condition Reports

'

CR No. Title

96-0636 Discrepancy between as installed and drawing

'

96-0721 Ineffective corrective action

j 96-0709 45 DCNs found in box

96-0509 Diesel generator differential temperature

96-0724 Failure to perform 50.59 analysis

96-0881 Problem with plant temporary modification procedure

96-0482 Unauthoriz0d modification

96-0729 Vibration points in alert range

96-0763 Test equipment attached to diesel

96-0816 Nontested valves used for containment isolation

96-0626 Inspection document sheet incorrectly completed

96-0737 Contractor control deficiencies

96-0215 Breaker spares

96-0316 Unauthorized modification i

96-0363 Procedural problems

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96-0689 Unauthorized modification

94-0712 Unauthorized modification

96-0607 Valve does not conform to vendor drawing

95-1159 Supports found not matching as-built drawings

96-0422 Unauthorized modification

96-0604 Misread PM card - Operated on wrong Diesel Generator Supply Fan

96-0474 Operator bumped relay 13A-K31 causing a half group 5 isolauon

96-0765 PMT performed for MWR 95-2979 without Shift Supervisor review

96-0763 Test equipment left attached to Diesel Generator after it was declared l

operable

96-0585 NRC Information Notices and associated responses were inappropriately

stored ,

96-0481 Added PMT for MWR 96-0684 was made without engineering review l

96-0527 12.5kV disconnect switches mispositioned during Aux Boiler Start  ;

96-0446 Drawings in MWR 96-0537 were stamped with an expired date j

95-0856 Halted PM 06452 due to Procedure 14.27.5 did not indicate entry into an i

LCO

95-1380 Failure to isolate sensing line during flushing of condensing chamber sensor  !

caused scram l

96-0433 MS-V-159 was missing caution tag

06-1081 PC-MOV-1303MV was found open during LLRT after being tagged closed

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96-0406 Divers were in 'D' Circ. Water Pump Bay D2 without signing on clearance

order

95-1327 Danger tag for 'A' Condenser Booster Pump A inadvertently removed

96-0236 In Procedure 6.1DG.401 Acceptance Criteria for fuel oil transfer pump vias

outside operability limit

95-1158 Welders inadvertently cut through energized heat trace

Problem Identification Reports

PIR No. Title

1-17287 SW-MOV-MO650 initially f ailed to close

2-05772 Flow indicator found sticking

2-00478 Relief valve lifted early

2-00641 Potential unauthorized modification

2-00925 As-found values out of tolerance

2-00928 As-found values out of tolerance

2-00353 Unauthorized modification

2-00658 Chemical addition tank overflowed

2-01723 Operability basis not sufficiently documented

2-04386 Housekeeping issue in HPCI room

2-07235 Sump cover bolts missing

2-02370 Failures of GE relays

2-01574 Classification evaluation packages found in box

2-04979 Unauthorized modification

2-08241 Unauthorized modifications

2-01226 Unauthorized modification

2-00310 Water spraying from SW valve

2-05592 Service water supply leaking through

2-01141 Substandard quality fasteners

2-00594 As-found values outside limit

2-02131 Service water pump lift I'

2-03857 EDG cylinder exhaust differential temperature exceeded

2-01334 Configuration control

2-07022 Configuration Control l

2-07020 Configuration control

2-05770 Configuration control

2-05769 Configuration control

2-04511 Pump bearing high alarm

2-00319 Relief valve test stand

2-03656 DG muffler typass valve

2-03164 Failure to perform 50.F'* evaluation l

2-01582 MOV motor and operator classified nonessential l

2-03861 Valve failed to open and close

2-00243 RCIC pump high pressure suction alarm

2-01276 Check valve seat leakage I

2-22767 Movement of DG air intake line

2-01425 Missing screws on panel

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2-00451 Testing method for contacts

2-01706 Lack of procedure to address performance of self assessments

2-02162 RHR placed in shutdown cooling with temperature difference between RCS l

and RHR greater than 50 degrees.

1-20507- The KAMAN high range monitor failed the leak test. ,

2-02511 Failure to take readings within the time limit specified in Procedure 6.3.1.2. l

2-05528 DG-2 Room High Pressure CO 2 actuator cylinder missed 5 year hydro test l

2-03580 Annunciator R-1/B-4 ' Battery Room 1 A Temp'will not stay reset 1

2-05724 Annunciator FP-3/A 1 came in and cleared. Fire Pump C started. No fire l

2 03861 During performance of 6.HPCI.101, HPCI-MO25 failed to open and close i

2-02070 Found RMV-V-301 shut. Should have been open  ;

2-02071 Intentiona'ly entered LCO due to fire door N103 being made inoperable  ;

2-03957 Large fan used/ stored in Aux Relay room not secured. Seismic concern l

2-03912 AC-V 70 Feedwater stop valve for electrode boiler found in open position i

2-03016 EOPs direct entry into procedure 2.2.69.2. Provides conflicting steps during j

ATWS

2-01426 Potential for RHR waterhammer exists per GE plant experience report

2-06736 SW-TCV-451 B failed to stroke open within time limit  !

2-04841 When DG-2 was declared inoperable, verification of ECCS operability was

not logged in SS Log

,

2-01835 Weld rod oven receptacle not energized j

l

2-03817 'E' Fire Pump is steam bound due to running dead headed for 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> J

2-03287 Clearance Order 96-680 issued for MWR 95-3868,which had already been  !'

completed

2-05601 RWCU-MO-M015 failed to cycle with IST operability limit

2-03497 Temperature of holding ovens for weld rods was not verified or logged 'i

2-02382 Surveillance Procedure inadequacy

2-04210 Mechanical personnel walked down MWR 961399 without work control

center authorization

2-01738 Two incidents identified of failure to sign off steps in procedures when work

,

was completed

! 2 04570 Communication problem resulted in procedural step in Procedure 6.PAM.304

l not being performed

2-00573 Housekeeping around SLC Tank Access cover is poor

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2-04962 Sketch SKE-DG-235 for Minor Maintenance 95-174 provided erroneous

j information

2-04475 RWCU Pump A has indications of melted coupling, Mechanical seal and

discharge line leaking water

2-05557 Inappropriate installation of Drywell Reliable Air Supply Check valve lA-CV-

l

14CV

2-05564 EPA 1 A4 tripped on under voltage. Caused loss of Mernate power to RPS

bus A

2-07054 Surveillance Procedure 6.FP.102 step 8.2.70 calls for local alarm to sound. It

did not

. 2-02511 Failure to take readings within the time limits specified in SP 6.3.13.2

2-07050 SP 6.2DG.301 acceptance criteria for steps 8.12.1 and 8.12.2 were not met

2-04205 Weld sheets and drawings give conflicting information on material to be used

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2-05807 Procedure 14.2.5 did not provide calibration tolerances for ICPS voltages

2-04805 Failure to initial a step in Procedure 6.1 ARI.301

2-04397 Significant increase in CS Pump B vibrations

2-02514 Fan units in DG rooms 1 and 2 have had their expansion joints painted over

2-03279 Limitorque Spare Motor 04299 apparently repaired by unqualified vendor

2-01714 ASME Section XI pressure test was not performed at the specified required

l

test pressure ,

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2-01716 Inadequate and Untimely review was performed on Pressure test Nos.95-492 and 95-493 ,

2-02038 Outage Schedule called for MSIV closure during power ascension at f

50-70 percent power. Not achieved on time, requiring power reduction to

perform

2-00536 Deficiencies noted with tool and equipment control in FME Zone I around

spent fuel pool

2-00094 Scaffol&ng boards noted to be butted up against A Air Compressor

Aftercooler Moisture Separator

l Engineering Project Requests

l

EPR No. Title

I

I

96-097 Review SW piping analysis / hanger calculations95-168 Exhaust fan power from division 11

,

Maintenance Work Requests

MWR No. Title

96-1092 Adjust packing

96-1514 Excessive oilleak

96-1095 .DG muffler bypass valve failed

96-1162 Flow indicator problems

96-1126 Exhaust f an for DG room

96-1530 DG oil day tank high alarm level

96-1406 Screen wash pump discharge joint leaking

96-1238 ADS control logic

96-0747 RCIC turbine terminal box is loose

96 1012 SW pump discharge pressure low

96-1125 DG muffler bypass valve

96-1039 Circulating water pump motor

96-1673 RCIC test return root

j 96-0883 Repair Control Rod Drive Pump 'A'

96-1500 Repair Diesel Generator Day Tank No. 2 High Level Pump Stop

96 1279 Repair Service Air Compressor i

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Miscellaneous Documents

Technical Specifications

Final Safety Analysis Report

NRC Inspection Report 50-298/87-10, dated September 22,1987

l NRC Inspection Report 50-298/89-03, dated April 10,1989

NRC Inspection Report 50-298/89-22, dated July 24,1989

NRC Inspection Report 50-298/90-33, dated November 21,1990

NRC Inspection Report 50-298/91-02, dated October 1,1991

3pecial Test Procedure 87-011, Post-LOCA Service Water System Flow Test, dated

May 21 and May 25-26,1988

Nebraska Public Power District letter dated July 24,1987, to U.S. Nuclear Regulatory

Commission; Subject: Safety System Functional inspection at Cooper Nuclear Station,

Brownville, Nebraska

Nebraska Public Power District letter dated August 14,1987, to U.S. Nuclear Regulatory  ;

Commission; Subject: Safety System Functional Inspection at Cooper Nuclear Station,

Brownville, Nebraska

Nebraska Public Power District letter dated November 23,1987, to U.S. Nuclear

Regulatory Commission; Subject: Nebraska Public Power District's Response to inspection

Report No. 50-298/87-10

NRC Memorandum dated December 22,1987 from William O. Long, Project Manager,

Project Directorate - IV, Office of Nuclear Reactor Regulation, to Mr. George A. Trevors,

Division Manager - Nuclear Support, Nebraska Public Power District; SUBJECT: SAFETY

SYSTEM FUNCTIONAL INSPECTION, 50-298/87-10

MEMORANDUM dated November 6,1967, from F. Hess to I. Gabel, SUBJECT:

W.O. 2520-02, Consumers Public Power District Design of Reactor Building Closed Cooling

System

BR-65, Reactor Building Closed Cooling Water System Summary of Preoperational Test,

dated October 31,1973 and completed data for this test

MEMORANDUM dated December 12,1973, to E.M. Kuchers from F. Hess/H.Reh/l. Gabel;

SUBJECT: Work Order 2593 NPPD Cooper Nuclear Station BR-65 RBCCW System

Summary of Preoperational Test (11/28/73)

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Cooper Nuclear Station, Response to 10 CFR Part 50 Appendix R, " Fire Protection of Safe

Shutdown Capability," Volume I and 11, June 28,1982 l

1

l Cooper Nuclear Station, Response to 10 CFR Part 50 Appendix R, " Fire Protection of Safe !

Shutdown Capability," Volume Ill, December 2,1983

L

Cooper Nuclear Station, Appendix R Program Validation Project Plan, Revision 1, l

November 15,1996 i

l

Cooper Nuclear Station, Project instruction PI-004,10 CFR Part 50 Appendix R Functional i

Requirements Analysis, Revision 0, N Jeber 4,1996 l

1

l_ Cooper Nuclear Station, Project instruction PI-003, Fire Protection Features Assessment,

.

Revision 0, October 11,1996 ,

!

Cooper Nuclear Station, Project instruction PI-006,10CFR50 Appendix R Manual Action I

Feasibility, Revision 0, November 8,1996 j

i

l Cooper Nuclear Station, Project Instruction Pl-001, Appendix R Safe Shutdown Equipment  !

List, Revision 0, November 8,1996

i 1

Cooper Nuclear Station, Project instruction PI-002, Cable Selection and Validation,  :

Revision 0, October 11,1996 l

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Cooper Nuclear Station, Safe and Alternative Shutdown Analysis Report, July 1996  !

!

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Cooper Nuclear Station, Appendix R Program Validation Project Plan, Revision 1, dated  ?

November 15,1996  !

I

Cooper Nuclear Station OER Desktop Guide 5, Guideline for the Communication of Industry

Operating Experience to CNS, Revision 1, Dated July 16,1996

NRC Safety Evaluation Report, Fire Protection Program, May 23,1979

l

NRC Safety Evaluation Report, Exemption Requests - 10CFR 50.48 Fire Protection and

Appendix R to 10 CFR Part 50, September 21,1983

l

l

NRC Safety Evaluation Report, Safety Evaluation for Appendix R to 10 CFR Part 50,

items Ill G.3 and Ill.L, Alternative or Dedicated Shutdown Capability, April 16,1984  ;

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NRC Safety Evaluation Report, Outstanding Fire Protection Modifications, August 21,1985

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