IR 05000445/1990020

Insp Repts 50-445/90-20 & 50-446/90-20 on 900529-0615.No Violations Noted.Major Areas Inspected:Performance of Startup & Testing Activities Involving Unit 1 Prior to Proceeding Above 50% Power.No Insp of Unit 2 Conducted

ML20055J151
Person / Time
Site:	Comanche Peak
Issue date:	07/23/1990
From:	Joel Wiebe NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20055J149	List: IR 05000445/1990020 ML20055J148
References
50-445-90-20, 50-446-90-20, NUDOCS 9008010129
Download: ML20055J151 (30)

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APPENDIX

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U.S. NUCLEAR REGULATORY COMMISSION I

REGION IV

i NRC Inspection Report:

50-445/90-20 Operating License:

NPF-87_

50-446/90-20 Construction Permit: CPPR-127 Dockets: 50-445

50-446 Licensee: TV Electric Skyway Tower

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400 North Olive, L.B. 81

Dallas, Texas 75201

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Pacility Name:

Comanche Peak Steam Electric Station, Units I and 2 f

(CPSES)

Inspection at:

CPSES, Somervell County, Texas

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Inspection Conducted: May 29 through June 15, 1990 l

Inspection Team:

J. S. Wiebe, Team Leade., Region IV

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M. Malloy, Assistant Team Leader, NRR W. R. Bennett, Senior Resident Inspector, Region IV J. B. Cummins, Reactor Inspector, RIV P. H. Harrell, Senior Resident Inspector, Region IV

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l T. J. Kenny, Senior Resident Inspector, Region !

J. L. Pellet, Section Chief, Regian IV

NRC Consultants:

D. A. Beckman, Parameter Inc.

G. G. Rhoads, Parameter, Inc.

Approved:

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J S. Wiebe, T6am Leader, Region IV te'[~

Inspection Summary i

Inspection Conducted May 29 through June 15.1990 (Report 50-445/90-2A 50-446/90-20)

Areas Inspected:

Special, announced inspection to assess licensee performance i

of startup and testing activities involving Unit 1 prior to proceeding above 50 percent power.

Specific areas reviewed included followup of previous team

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inspection findings, followup of previous team inspection violations / deviations, operations, maintenance, startup testing, surveillance, testing, problem

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identification system, and self-assessment.

No inspection of Unit 2 was cor, ducted.

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Results:

Licensee actions on previous inspection findings and commitments were adequate. Two items were left open.

The first concerned the licensee's connitment to augment management positions and shifts with previously experienced advisors and duty managers. This item was left open pending NRC review of the licensee's eva'uation of the effects of terminating this commitment. The second item concerned the licensee's commitment to upgrade plant labeling. This item was left open pending licensee completion of the commitment.

Licensee corrective. action for violations and deviations was good.

Strengths were noted in the licensee's implementation of the instrument and control supervisor's observation of field activities program and in the periodic valve lineup program.

In the operations area strengths were noted in the shift turnover process and in control room operator response to panel alarms.

Occasional problems were noted in crew-to-crew communications of information not directly associated with plant status and also communication between the crews and other departments.

Strengths were noted in the maintenance organization, engineering and planner support of maintenance, and computer systems used to support maintenance. No specific strengths or weaknesses were noted in the area of startup activities.

In the area of surveillance activities, weaknesses were noted in the quality of procedures and the

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scheduling of nonroutine surveillances.

The team noted that the licensee was taking action to correct these weaknesses.

In the areas of problem identification, reporting, and resolution, no specific strengths or weaknesses were noted.

Specific problems with reports to the NRC were corrected by the licensee. The NRC's review of the licensee's self-assessment showed that it was detailed, coglete, and generally reflected the same perspective as that of this report.

Overall the licensee's performance from fuel load to 50 percent power was considered good. No issues were identified which would impact operation abve 50 percent power.

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DETAILS 1.

Persons Contacted

• J. M. Ayres, Quality Assurance (QA), Program Manager

• 0 Bhatty, Issue Interface Coordinator

• K. C. Bishop, Consultant, Rates & Regulation

• M. R. Blevins, Manager of Nuclear Operations Support

• W. J. Cahill, Executive Vice President, Nuclear

• V. P. Cornell, Dallas Licensing Engineer

• J. L. French, Independent Advisory Group

• W. G. Guldemond, Manager of Site Licensing

• C, B. Hogg, Chief Engineer

• T. A. Hope, Site Licensing

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• J. J. Kelley, Jr., Plant Mtnager

• H. Lawroski, Administrative Consultant

• E. F. Ottney, Project Manager, CASE

• M. D. Spence, President, Generating Division

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• G. J. Stein, Technical and Administrative A.*sistant, Maintenance i

• J. F. Streeter, Executive Assistant, Generating Division

• C, L. Terry, Director of Quality Assurance, Nuclear Engineering

• 0. L. Thero, CASE i

• B. W. Wieland, Manager, Maintenance

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The NRC inspectors also interviewed other applicant employees during this

inspection period.

• Denotes personnel present at the June 15, 1990, exit interview.

NRC personnel present at June 15 exit meeting.

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D. D. Chamberlain, Chief, Project Section B

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A. T. Howell, Resident Inspector R. M. Latta, Resident Inspector R. D. Martin, Regional Administrator J. S. Wicbe, Chief, Project Section D J. H. Wilson, Sr. Project Manager 2.

Followup on Previous Team Inspection Findings (92701)

The objective of this portion of the assessment was to review the findings

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l of team inspections, review and evaluate the licensee's actions in response to the findings, spot check the. licensee's actions, assess actions that are not complete or are not adequate, and obtain background

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and technical information to allow the NRC to make a determination concerning the acceptability of allowing Unit 1 power escalation above 50 percent.

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(0 pen) Open Item (445/89200-0-01): Applicant committed to augment t

facility management positions and operating shifts with previously

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f experienced advisors and duty managers until the completion of the power ascension test program.

The team verified that the commitment was being met. The effect of the advisors varied.

Some appeared to provide good, timely advice to

the shift.

Others appeared to stay in the background and their

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involvement with shift activities appeared to be slight. Overall,

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the advisors appeared to have a positive influence on shift t

activities.

The effect of the duty managers also varied. Although

the licensee has documented the duties and authorities of the duty

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managers, it appears that additional clarification of managements'

role would be helpful.

Since the NRC's assessment and the itcensee's self-assessment is based on operations with these programs in place, the team expects

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that, prior to terminating these programs, the licensee will evaluate

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the effect of their termination.

The team does not recommend that the programs be in place any longer than necessary, but expects that

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this evaluation confirm that the original commitment was adequate based on knowledge and experience gained since the programs were put in place.

This item remains open pending expiration of the commitment and NRC review of the licensee's basis for terminating these programs, b.

(Closed) Open Item (445/89200-0-03):

Ensure that communications within and between organizational elements does not become a problem.

This open item involved five examples of communication problems..

Four of these problems occurred in areas evaluated elsewhere in this report.

The fifth example involved communications between

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maintenance work crews and control room crews. The licensee has several programs in place that are aimed at assuring adequate l

communications.

The team found that the Site Operations Review l

Committee (SORC) had initiated Action Item 90-031 and formed a l

five person evaluation team to determine if interdepartmuntal communication problems existed and to established a broad response to

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such problems. The SORC evaluation team had_four basic findings and five corrective action recommendations involving specific procedure changes, general guidelines for interfaciniprocedures,

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identification of organizational and functional responsibilities, and training.

The final evaluation team report was issued on May 31, 1990, and the corrective actions had not yet been completed.

Additional responses to the NRC concern include:

(1) preshift meeting held by the oncoming _ operating shift with craft and support personnel; (2) the maintenance and instrumentation and control (I&C)

departments implementing a field observation program to increase the presence and effectivenecs of craft supervision in the field; and (3) the operations department has implemented periodic reviews and performance evaluations of shift operations, training, and-

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individual performance. This latter program is specified by Operations Work Instruction (0WI)-302, " Operations Department Management Periodic Review," Revision 4.

The team reviewed the results of the OWI-203 program after December 1989 and found that, although the program is set up for an annual cycle, relatively few -

(estimated 10-20 percent) of the evaluations had been documented.

Operations staff personnel indicated that the operations department'

manager was monitoring the evaluation requirements, but acknowledged that startup workloads.had affected the success of the program.

Although, some actions to improve communications continue, in general, licenses actions in thi> area have been effective.

Effectiveness of communications was also evaluated in conjunction with the other parts of this inspection and was found to be acceptable.

This open item is-closed.

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(Closed) Open Item (445/89200-0-04):

Define, develop', and_ implement safety evaluation training for SORC members.

At the time the initial operational readiness assessment team (ORAT)

inspection was performed, there was no requirement for the SORC i

members or alternates to be qualified to review and/or approve

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10 CFR 50.59 reviews and evaluations.

In response to the open item, the licensee issued a change to Administrative Procedure STA-401,

" Station Operations Review Committee." Procedure Change

Notice (PCN) STA-401-416-3 required all members and alternates of.

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SORC prior to February 16, 1990, to meet the quali.fication i

requirements of STA-707, "10 CFR 50.59 Reviews," by May 31, 1990.

The change requires any new members to satisfy the same requirements within 90 days of their appointment to SORC. The team reviewed documentation which demonstrated'that, as of May 21. 1990, all alternates / members of the SORC had i,atisf actorily completed.the training required by STA-707.

This open. item is closed.

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(Closed) Open Item (445/89200-0-05):

Improve implementation of program for updating system. status drawings.

During the initial ORAT inspection, the team was concerned about the ability of the plant operators to properly maintain the system status drawings as required by Procedure ODA-410. " System Status Control."

At the time of that inspection, the licensee intended to fully implement the status control system, as written, using laminated system drawings to reflect current system configuration.

Since the

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status control program and has had the opportunity to use the program

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sufficiently to determine its effectiveness. The licensee is

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currently performing weakly audits of the drawings in an attempt to assure that they are accurate. The team discovered thet these audits

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are uncovering an average of one discrepancy per month.

Based on the lessons learned with the status control system, the

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licensee is in the process of revising ODA-410 to phase out the status drawings as the primary method of status control.

These will

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-6-be replaced with a syitem that requires the operator to check several different program documents, such as clearances, temporary modifications, locked valve control program, instrumentation and annunciators, operator aids, and system status lineup files. The new program illl use control board status aids to ensure status information on components, such as filters and demineralizers, is readily available'to the operator.

The revised program will still permit,the use of the laminated drawings as a mechanism for statusing systems, but it will no-longer be the only method and will no longer be required at all times. The program will also include a random sampling of system lineups to give sdded assurance that the system status program is adequate.

The team reviewed the proposed revision to ODA-410, which defined the new program.

Based on review of this procedure, the team had no further questions in this area.

This open~1 tem is closed.

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(Closed) Open Item (445/89200-0-08):

Licensee commitment to provide management participation in operability drills.

The drill program was completed concurrent'Iy with the completion of the initial ORAT inspection in late January 1990. Subsequently, management participation in the drill process'was extended to resolution, approval, and tracking of drill deficiencies.

The team reviewed tracking reports for January through May 1990 and discussed the program and lessons learned with licensee statf.

The team concluded that closcout of the program and completion of the open drill items were being acceptably managed. This open item is closed.

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(Closed) Open Item (445/89200-0-09): Applicant committed to review the fdentified deficiencies and correct those that affected the operability of safety-related systems.

This item was reviewed by the NRC onsite staff prior to issuance of the low power license. This review was documented in NRC Inspection Report 50-445/90-07; 50-446/90-07.

This' item is closed, t

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(0 pen) Open Item (445/89200-0-10).

Complete the plant labeling J

upgrades by completion of the first refueling outage.

In conjunction with Open Item 445/89200-0-11, the team reviewed the

labeling program status with the licensee's labeling task group

supervisor.

Completion is still targeted for the first refueling outage. About 43,000 labels are currently installed (about one half of the total for Unit 1). An additional 23,000 are on order, including approximately 10,000 piping labels not included in the original planning for con.pletion during this operating cycle.

Some production shortfalls have occurred, apparently, due to additional engineering required to support development of master equipment list equipment nomenclature and data needed for specifying and ordering labels.

The engineering is scheduled for completion in August 1990, i

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I The licensee has implemented a recovery plan to regain the original

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production target and progress is being monitored by licensee

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management up through the vice president of operations. This item

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will remain open pending NRC confirmation of completion of the

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labeling program.

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-(Closed) Open Item (445/89200-0-11):

Evalante and insta*1 valve labels for the instrument air system.

NRC Inspection Report 50-445/90-07; 50-446/90-07 documetted review of the licensee's preparations for Unit I fuel load and lor power operation.

During the current inspection, the team confirmed that i

all remaining instrument air valves had been labeled with about a dozen exceptions involving minor discrepancies. These exceptions were primarily in the balance-of plant or unit common systems and had no impact on safety-related or nuclear steam supply system

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operations.

This open item is closed.

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(Closed) Open Item (445/89200-0-12):

Identification and correction of procedural deficiencies.

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During the 'nitial ORAT inspection, the licensee did not appear to be

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aggressively correcting minor procedural discrepancies, but rather appeared to be working around the problem.

ND.C Inspection Report 50-445/90-07; 50-446/90-07 discussed the interim review of a licensee-issued directive on correcting pr9cedural. problems and

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concluded that the issue was adequately resolved for the issuance of

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the Unit 1 low power operating license.

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l During this inspection, through direct observation of pe'rsonnel in the plant using procedures and indirectly through the review of licensee generated reports such as QA,urveillance reports, the team

noted that there appeared to be'an increased emphasis on correcting procedure problems. However, as noted in Section'7 of this report, the team observed cases where the personnel did not strictly follow procedures.

The licensee has a task force effort under way to further improve procedure quality.

Based on these reviews and the

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progress made, this open item is closed, i

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(Closed) Open Item (445/89200-0-13):

Implementation of system engineers training program.

The initial ORAT inspection found that tht rystem engineers had not l

received dedicated systems training.

This had been previously identified by the licensee who committed to implement a professional staff training program by August 1990.

During this inspection, the team reviewed the status of the training program develooment.

Several actions have been accomplished since the initial ORAT inspection. Administrative Procedure STA-108,

" Professional Staff Training and Development Program," has been

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This procedure will provide the overall training-program for all managers, supervisors, and engineers (including system engineers).

There will be two types of system training as part of the program.

First, as part of an engineer's initial training, system training will be provided as designated on the individual's training matrix.

The training department is in the process of converting licensed operator training material for this purpose.

This training material is presently scheduled to be converted by August 1990..The areas to be covered include applied fundamentals, integrated plant operations, simulator training, and transient and accident analysis.

The licensee will continue to have the general plant information course available as well.

Secondly, the training department is developing detailed systems modules which could be used to give more detailed systems training on an as-requested basis.

This training material would only be used if the individual's supervision felt the need to request that a more detailed course be given.

In discussions with technical support department personnel the department is in the process of evaluating each individual;s training and experience, and has commenced generating training waiver requests for those incumbent engineers deemed to already possess requisite knowledge.

New engineers will be expected to complete their initial training within 26 weeks of arrival.

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year, the technical support department has put together a training I

record for each individual assigned to the departrient.

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aid in tracing the training of individual technical support i

personnel.

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In conclusion, the team determined that the licensee is making progress in developing system training for system engineers and is

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on track to meet the August 1990 commitment of implementation.

Based on this review, this item is closed.

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(Closed)OpenItem(445/89200-0-14):

Implementation of the nuclear plant reliability data system (NPRDS) reporting system.

i During the initial ORAT inspection the licensee's methods for trending and reporting failures to the Institute of Nuclear Power Operation's (INP0s) NPRDS had not been implemented. During this inspection, the team reviewed the status of the system engineering trending program and NPRDS. Although the commitment to begin submitting information to NPRDS was not effective until the commencement of Unit I commercial operations, the licensee commenced submitting failure reports in early April 1990. The team reviewed an

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example of a failure report which had been submitted and had no questions. The licensee is in the process of updating its engineering records to acco at for changes or discrepancies in the original engineering records, submitted to INPO, and expects to have this project completed by commercial operations.

However, this project does not affect the submittal of failure reports to the NPRDS.

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The licensee is also in the process of implementing its performance.

monitoring program per STA-736, " Equipment Performance Monitoring,"

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Revision 0, and STA-680, " Equipment History Program," Revision 1.

Presently the system engineers are determining the base set of

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parameters to be monitored by the program. This will be an

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evolutionary type of program, changing as plant history indicates additional points,to be monitored and parameters that are not required to be monitored.

Based on the facts that the NPRDS has been implemented and the

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performance monitoring system has reached a point where the system i

engineers are formulating the parameters to be monitored, this item

is closed.

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(Closed)OpenItem(445/89200-0-15):

QA involvement in operations.

At the time of the initial ORAT inspection, the team was concerned that there was not enough evidence of day-to-day involvement of the QA organization. At that time, the QA organization had just undergone a reorganization to a more operationally oriented

alignment.

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During the current inspection, the team reviewed recently performed QA surveillances and held discussions with members of the QA organization.

The team also noted that QA involvement had been observed in plant operations by other recent NRC inspections, such as the March 1990 augmented inspection team inspection (see NRC Inspection Report 50-445/90-11; 50-446/90-11).

The level of QA involvement in real-time operational activities appears to be acceptable.

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The licensee also has actions under way in the QA organization to increase its effectiveness. These include training in areas such as

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performance-based audit techniques, observation training, and I

root-cause analysis.

The organization has continued to hold lessons-learned and team-building meetings which had been narted in late i

1989.

The QA organization has also started issuing a biweekly "QA

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Technical Newsletter" to better inform QA personnel of what_is happening in the plant and within the QA group. This newsletter appears to be an excellent way to keep personnel informed of current events and expectations.

One side issue was identified as a result of_ reviewing QA Surveillance Report QAS-90-492. The report included the results of a QA observation of operations and maintenance personnel reacting to a

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iow nitrogen pressure alarm on the No. 4 feedwater isolation valve.

The surveillance report stated that the alarm setpoint was 2250 psig, but that a technical evaluation (TE-90-1613) had determined that the

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-10-valve was still considered to be operable as long as the nitrogen-pressure was greater than 2040 psig.

The team reviewed the technical evaluation and found that it was based cn the valve being operable at nitrogen pressures down to 2040 psig based on a valve vendor's letter (Borg-Warner Fluids Control Division letter dated May 16,1990).

This letter stated that the minimum nitrogen pressure to close the valve in 5 seconds is 2040 psig within an ambient temperature range

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of 70-130*F.

Technical Specifications Surveillance 4.7.1.6 requires this valve to close in 5 seconds when tested pursuant to the inservice test program.

The team reviewed Surveillance Procedure OPT-511

"Section XI Testing of Steam Generator Feedwater Valves " Revision 0.

Sections 9.2 and 9.3 contain the steps to test this valve to meet the surveillance timing requirement. This procedure ~does not contain n y

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requirement to monitor or record nitrogen pressure during the timing test.

In discussion with the licensee performance and test group, it was determined that, to their knowledge, no preoperational or inservice test ever correlated nitrogen pressure with closing times for the valves and no testing had been performed to verify the valve vendor's letter.

The team could not determine, based on the valve vendor's letter, how the 2040 psig value had been determined. This item is open (0 pen Item 445/9020-01) pending NRC review of the basis for considering the value operational at 2040 psig accumulator pressure.

. L Based on its review, the team concluded that the QA organizat;on has made a transition to an operationally oriented organization and considers Open Item 445/89200-0-15 closed, (Closed) Open Item (445/89200-0-16):

Improvement needed in root cause m.

analysis and corrective action identification programs.

As discussed in Section 9 of this inspection report,=the licensee

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has taken-actions to strengthen these programs. The team determined that the licensee had developed and implemented adequate programs to address root cause analysis and corrective actions, o

This item is considered closed, (Closed) Open Item (445/90014-0-01):

Luminescent striping on 6.9kV n.

switchgear.

During the ORAT inspection performed prior to issuance of the Unit 1 full power operating license, an inspector questioned the use of luminescent striping on certain breakers of the 6.9kV switchgear and received different answers from each interviewee.

During this inspection, the team discussed this item with operations department management and was told that the breakers needed to respond to a l

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-11-10 CFR 50 Appendix R-type. fire were marked in this fashion. The licensee presented Abnormal Conditions Procedure (ABN)-803A,

" Response to a Fire in the Control Rocn or Cable Spreading Room,"

Revision 1, which had numerous notes indicating that the striping was used for all breakers and junction boxes requiring manipulation by the procedure.

Operations department supervision also indicated that after the item-was originally identified by NRC, all shifts were reminded of the meaning.of the luminescent striping in shift-turnover meetings.

During this_ inspection, operators and all personnel queried were aware of the tape's use.

In addition, auxiliary operators (A0s) will receive training on this issue during their requalification training.

Based on_this review, the team had no further questions.

This item is closed, o.

(Closed)OpenItem(445/90014-0-02): Definition of " inoperable" as used in Procedure ICA-102, " Instrumentation and Control Troubleshooting Activities."

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The meaning of the word " inoperable," when used in reference to troubleshooting activities, was questioned by an inspector during the prefull power operating license ORAT for Unit 1.

Specifically, the inspector questioned whether the word " inoperable" meant

"out of service" when applied to non-Technical Specifications-related systems, or whether " inoperable" was intended te be used with reference to Technical Specifications-related systems only.

During the current inspection, the team found that th? licensee addressed this item in two ways.

First, the licensee confirmed that the word " inoperable" is to be used only in a Technical Specifications context.

Secondly, the licensee clarified ICA-102 to clarify the following points:

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During troubleshooting activities, the affected system, components, or channels, may be functional or running.

• Safety-related or Technical Specifications-related equipment must be evaluated for operability.

• If troubleshooting takes place on functional or running equipment, all activities must be coordinated and controlled with operations.

The inspector had no further questions.

This item is closed.

In summary, one open item was identified for a technical issue that was unrelated to the previous findings.

Licensee progress on address:ng the involved issues was adequate.

No items were identified that would lmpact l

operations above 50 percent power.

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Followup on previous Violations /Deviat 4ns (92702)

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(Closed) Deviation (445/89200-D-06):

Failure to provide lineup controls for fuses and low voltage breakers.

The licensee responded to the deviation in Letter TXX-90133 dated i

April 9, 1990. The results of NRC's review of initial licensee i

actions were documented in NRC Inspection Report 50-445/90-07; 50-446/90-07 including results of review of licensee-completed lineup checklists, fuse verification checklists, and resolution of

licensee-identified discrepancies.

During this inspection, the team reviewed permanent procedure revisions. 0WI-208, "12V AC/DC Breaker Verification," was issued on June 11, 1990, and provides adequate control.

The performance of OWI-208 would be triggered during startup by IP0-001A, " Plant Heatup from Cold Shutdown to Hot Standby,"

Step 5.2.26.

This step includes the requirements to perform the breaker lineup varification but does not currently include the specific new procedure number. A PCN has been processed to include the procedure number.

Operations Standing Order 90-01, " System Status Updates, Work Order /LCO Control, and Fuse Control," was issued on January 31, 1990, and details adeauate step-by-step actions to be taken when removing and reinstalling fuses for clearances.. This order is scheduled to expire on December 31, 1990.

STA 605, " Clearance and Safety Tagging," Revision 8, was issued on April 20, 1990, to provide permanent instructions.

The team confirmed implementation by review of completed clearance and lineup documents and discussions with plant operators.

The licensee's actions are acceptable. This deviation is closed, b.

(Closed) Violation (445/89200-V-02):

Failure to take prompt corrective action for an identified deficiency on safety-related instrument valve lineups.

The licensee had initially identified a deficiency in the performance of safety-related instrument valve lineups during the TV Electric Operational _ Quality Assurance Team (00AT) review. _The_0QAT finding was incorrectly considered resolved when instrumentation and control (I&C) management indicated that the INC-2100 series procedures covered the valve lineups. The QA organization did not verify that the procedures were, in fact, being used, but closed out the item based on the fact that the procedures existed.

The NRC ORAT determined that the INC-2100 series procedures were not in use.

This violation dealt with the fact that the 0QAT finding was incorrectly closed and questioned the comprehensiveness of the resolution of the remaining 00AT findings.

The licensee responded to the violation in Letter TXX-90133, dated April 9, 1990. NRC Inspection Report 50-445/90-07; 50-446/90-07 documented the interim NRC review of this item and concluded that the issue was adequatel, resolved to support issuance of the Unit 1 low power operating license.

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The licensee's letter stated that the other OQAT findings and I

resolutions were rereviewed by the responsible managers to assure

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adequacy.

It also stated that the QA organization reviewed its acceptance of the responses to the original findings to assure that the NRC-identified violation was not a generic problem.

The response concluded that the identified problem was not generic but was an isolated case.

t During this inspection the team reviewed the licensee's corrective actions taken in response to the violation. The resolution to the instrument valve lineup problem is discusstd under Violation 445/89200-V-07 below.

The team also reviewed the licensee's internal documentation of the QA organization's and the line department's rereview of the 0QAT items.

The team concluded that the licensee's response was adequate and that all licensee

reviews stated in the response to the violation has been completed.

This violation is closed.

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(Closed) Violation (445/89200-V-07):

(1) Failure to implement I&C valve lineup and independent vtrification procedures, and (2) failure to implement review and approval procedure requirements for a revised

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work order (W3).

(1) NRC verified initial licensee corrective actions for failure to perform I&C valve lineups and independent verifications during valve lineups and independent verifications during the period

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February through March 1990, prior to issuance of the Unit 1 low-power operating license.

The results of these verifications are reported in NRC Inspection Report 50-445/90-07; 50-446/90-07, t

During this inspection, the team verified the remainder of the licensee's actions specified in their response to,the violation (TXX-90-133). hbsequent to that NRC inspection, the licensee issued revisions to system operating procedures (SOPS) to provide permanently established lineup checklists. The I&C

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department has included additional guidance on independent verification in ICA-115. "I&C Section Verification Activities,"

Revision 1, PCN 2, and in ICA-101, "I&C Work utrol,

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Revision 1, PCN 2.

The team also reviewed the-licosee's records of training in these procec'*;re topics which w0s i

presented to all I&C personnel on January 30, 1990,.Fui+.her, the operations department is routinely conducting system l ineup l

verifications as a periodic check, '

1uding performance of the i

new I&C lineups for the selected systenu.

These periodic

alignment checks are considered by the inspection team to be a strength, in that they provide continuing assurance toat system configurations are correct.

In their response to the violation, the licensee had also committed to an enhanced program of field I&C activity

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observations.

ICG-004, " Observations," provides for I&C supervisors performing documented evaluations of field work

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activities as a "self-betterment" effort aimed at achieving more supervisory impact in the field. The procedure requires each supervisor to perform one work observation per month, and provides checklists to be used for both quantitative and qualitative grading of performance.

Since January 1990, about

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45 activitits have been observed, representing about 90 percent of the observations re aired by the procedure.

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management is stressing 100 percent participaticn. The team reviewed the 1990 data and the program results. Additionally,

the I&C department had begun trending operations notification and evaluation (ONE) form root causes.nd was using this data to

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evaluate departmental,serformance.

Future licensee plans include comparing the results of the root cause trends with the a

results of the supervisory observations.

The team considered these programs to be strengths.

(2) The subject of this portion of the violation was an electrical

WO that was revised, without notifying the shift supervisor, to increase its scope after additional equipment deficiencies had been identified.

In addition, an ONE form was not promptly i

initiated when the equipment and performance deficiencies were

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found, i

The licensee took initial corrective actions at the time af -

identification and they were reviewed in progress by,the NRC..

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The licensee's response to-the violation (TXX-90133) provided the actions taken to prevent recurrence. The licensee '.ssued Revision 13 to STA-606, " Work Requests and Work Orders," to-clarify the responsibilities and procedural steps fo' all

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parties involved in revising a WO. These changes were based upon an extensive root-cause investigation.

The investigation

included detailed analyses with an elaborate events and causal J

factors chart.

The procedure changes are responsive to the results of the analyses and clarify the requirements for work crew notification of the shift supervisor, shift supervisor evaluation of work scope changes, and review by quality control, radiation protection, and the code inspection agency. The

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licensee has completed training for the procedure changes.

Licensee actions to improve the use and effectiveness of the ONE form is discussed below in Section 8.

The effectiveness of communications between work groups is discussed below with the team's observation of maintenance and operations activities (Section 4 and Section 6).

The inspection team's observation of maintenance and related control room activities during this inspection did not identify any problems similar to those addressed by this violation.

This violation is closed.

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Licensee corrective actions for the above violations and deviation

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were adequate. No issues were identified that impact operations above 50 percent power.

4.

Operations (93806)

During the assessment period'on site, the team reviewed plant procedures,

'l licensee event reports (LERs) issued since Unit I fuel load, a sample of licensee ONE forms generated since fuel load reidting to operations

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procedure use and compliance, unit and shift supervisor logs, night

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orders, policy statements, and overtime records.

The team also interviewed the plant manager, the operations manager, and representative members of two operating crews and accompanied auxiliary

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operators on their rounds, Team members attended and monitored shift

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briefings for severa1' shifts. Most of the emphasis of the onsite assessment was placed on monitoring control room activities, including normal operations activities and scheduled surveillance testing.

The team reviewed several' aspects of the licensee's onerations activities as follows:

a.

Effectiveness of experience feedback from operations problems.

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The licensee's ONE form process appeared to provide good feedback for operations problems.

(See Section 9 of this report'for additional discussion of the licensee's ONE form program.)

In addition, the operations department utilized lessons learned, policy statements, and shift orders to relay lessons learned in a written = format. When interviewed, shift personnel were aware of recent operational problems.

Shift turnovers observed by the team regularly provided i

feedback on recent operational problems not previously identified by

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b.

Identification and correction of procedure problems.

Based on interviews with the operations manager and several shift personnel, the te m found that procedure problems are being identified that require approximately 100-150 procedure changes per month. These problems are being corrected promptly.' Shift personnel stated that procedures had improved significantly over the last year and that procedural errors were not causing operational problems.

This may be due, in part, to the procedure review / writing group, obtaining two unit supervisors that have been providing effective l

operational feedback to originators of procedure changes, c.

Shift personnel response to events, alarms, and instruments.

While observing control room operations, the team found that personnel responded to control room indications and alarms

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appropriately, assuring that the cause of the abnormal trend or alarm was understood in each case. As a result of alarms due to failed l

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control in manual. Both of these evolutions were performed in a l

professional manner. The operations manager stated that crew

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response to alarms had been a problem since Unit I fuel load, but its importance was being stressed and had improved recently.

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d.

Shift personnel use of procedures, Technical. Specifications, administrative controls, and the technical requirements manual.

f Shift personnel appeared to be aware of and satisfied procedural requirements during the team's control room observation. The team-

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did observe some minct procedural inconsistencies and brought them to the attention of the licensee. Reactor operators regularly used

alarm response procedures for unusual alarms or to confirm their

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diagnosis of events and conditions. Operators appeared to routinely-make boron dilutions to compensate for xenon buildup without reference to the appropriate procedure, which is permitted by station administrative procedures, and actions appeared to be in compliance with the governing system operating procedure, e.

Control room alarm, instrument, and recorder status with compensatory measure adequacy.

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During control room observation, the team noted a large number of f

annunciators to be continuously alarming. The boronometer was not indicating reactor coolant system (RCS) boron concentration correctly, but it was not tagged in any way.

Reactor operators that the team interviewed stated that the boronometer was not in' service i

and had not worked correctly since Unit 1 startup, except for a few days, and it was not normally used or relied upon.

Reactor operators stated that boron concentration was being updated from chemistry

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samples, which were taken each shift. This satisfied station administrative procedures, which would require more frequent sampling only when significant power changes are made with boron..However, during control room observation at approximately 5:30 p.m. on May 31, l

1990, the team found that the most recent sample posted, or in the unit log, was from approximately 10 a.m. on May 30, 1990. During the

interval, the operators had made several.small boron dilations to compensate for xenon buildup. When questioned by a team member, a reactor operator immediately called chemistry to request current.RCS and pressurizer boron concentrations. The information reported was from a sample taken at approximately 5:30 p.m. on May 31, 1990.

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f.

Tracking entry into and exit from Technical. Specifications action statements and shift awareness of plant status.

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The licensee covers Technical Specifications limiting conditions for operation (LCO) status and highlights craft activities affecting

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Technical Specifications during each shift turnover.

The team found that the licensee does not maintain a single' log or status board of

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all Technical Specifications LCOs, but rather has separate logs for

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LCOs entered briefly, which are expected to be cleared before the end

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of the day, and for LCOs of longer duration.

Team discussions with i

shift operators indicated that they are comfortable with this method, but that they also keep track of out-of-service equipment within their own logs. The previous cases of licensee failure to comply

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with Technicwl Specifications LCOs were judged by the team to be

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isolated instances of human error and not symptomatic of a systematic problem or weakness.

The licensee is continuing to review the adequacy of LCO tracking.

g.

Control room and external communications (outside operators and'other departments).

Communications within the crews observed by the team and between the control room and other groups were clear and. unambiguous.

Communications were normally confirmed and any unanticipated events or activities were communicated up the chain of command. Some crew =

members indicated during interviews that operations management occasionally bypassed shift management in directing shift activities.

During a plant tour with an auxiliary operator, a team member witnessed excellent communications between the operator and control room personnel while resolving a steam water hammer problem in the blowdown line to the high pressure drain tank, A team member also observed excellent communications during a second tour when the auxiliary operator was required to respond to a control room indication of a local panel alarm.

h.

Performance of activities outsidr the control room (e.g., tag-outs, equipment operation, and routine rounds; material condition of the plant).

The team accompanied auxiliary operators on their normal rounds in the plant. Activities appeared conscientious and thorough. A large number of steam and water leaks were observed in the turbine building. Discussions with operators indicated that few of these I

steam leaks were addressed during the recent outage.

The licensee indicated that there was an ongoing effort to identify and prioritize j

repair of steam leaks in the turbine building.

Plant cleanliness was

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good, j

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Shift turnover information transfer and shift planning.

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l The team found the licensee's turnover activities to be a strength of i

l plant operations.

Turnover activities included craft work planning

L information, including security, as well as normal operations activities and plant status information. The work planning and shift briefing activities were conducted in separate meetings.

In one observed case, the reactor operators, who do not routinely attend the

work planning meeting, were not informed that two containment entries

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were planned for the shift until after the first entry was concluded.

The panel walkdown and shift turnover by individua? operators in the

control room was observed and found to be very well performed.

Detailed attention to abnormal panel conditions and alarm status

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added to the strengths observed.

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The team noted several strengths in the licensee's performance in the area

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of operations.

Shift turnovers and briefings were thorough and detailed.

l Control room decorum and operations were conducive to safe operation of

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the facility. Control room logs were complete and explicit, such that-

plant operation and events were well documented and could be reconstructed from the logs. Administrative and operational tasks were conducted in a

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business-like manner. Operations management is committed to safe

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operation of the facility.

Finally, the improved procedure writing. groups

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are providing positive feedback to operators in a much shorter period than before (days versus weeks and months).

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The team noted that while performance in the area of operations was good, some areas need improvement.

The team noted minor procedure problems requiring attention. These included inconsistent use of the shadowed "1" to identify Unit 1 procedures. Also, some pages of the control room copy of Emergency Procedure E-0 had the flow chart upside down.

The diesel (

generator surveillance test appeared to be cumbersome as it requires use of both test and system operating procedures, rather than a single surveillance procedure.

Some plant organizations outside of operations did not appear to have

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fully recognized the increased response work load required by the-

transition to power operations.

Licensee management had previously (

identified this problem and was working on correcting it, r

Minor communications problems were identified within operating crews and

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between operating crews and other plant departments. These included the f ailure to update control room RCS boron concentration information from chemistry samples, failure of shift management to inform reactor operators of planned containment entries, and failure to inform auxiliary operators of the reason for some tasks relating to commitments'to outside organizations, such as the owners group.

The team concluded that the licensee displayed sufficient maturity and sensitivity to regulatory requirements to con inue to operate the plant in a safe, conservative, and orderly manner while escalating to full power.

Correction of the weaknesses identified could improve operations and are not required to be corrected by the licensee before increasing Unit.1 power above 50 percent.

No violations or deviations were identified. Several minor problems and

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observations were referred to licensee management. -No issues were identified that impact operations above 50 percent power.

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Followup on NRC Augmented Inspection Team (AIT) Findings for Inadvertent Single Train Safety Injection of March 12, 1990, NRC Inspection

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Report 50-445/90-11: 50-446/90-11 (92761)

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i At the conclusion of AIT onsite activities, the licensee's evaluation was

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ongoing. The AIT concluded that followup inspections should be performed to review the licensee's evaluation team final rer.ults in the following

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areas:

i a.

Auxiliary feedwater (AFW) control system problem.

The AFW system flow control valves had a pressure control function to protect the pumps from runout. When in manual control, as during startup, the valves closed on a pump start signal and then modulated open to maintain a minimum pump discharge pressure.

The valves were given an auto-open signal when a valid system auto-actuation signal

occurred but were then modulated by the pressure control signal.

During the subject event, the pressure control signal commenced'

closing the valves to increase pump discharge pressure after the

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auto-open signal had been received.

The pump startup was delayed by the safeguards sequencer and this allowed the valves to fully shut.

The valves eventually reopened, but each to different positions

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causing a mismatch in AFW flow and, consequently, steam generator (SG) water level, i

The licensee concluded that the valves closed due to the low-pressure

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signal resulting from the idle pumps.

The licensee determined this

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was an undesirable feature and processed Design Modification 90-157 t

to remove the pressure control and provide only the automatic full-open signal for automatic AFW system actuations. The difference I

in the two valves reopening was attributed to hydraulic differences l

in the two SG headers which resulted in a higher disk force for one

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valve than the other. This effect was eliminated by the new logic i

sequence resulting from the modification.

Postmodification testing confirmed that the modification successfully eliminated the problem.

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Additional testing and engineering analysis were also performed to assure that the system operating configuration resulting from the modifications would not cause the pumps to trip under the most limiting conditions of degraded bus voltage and feedwater pipe break.

The licensee's actions appeared consistent with the results of the evaluation and were considered to be adequate by the team.

The team-

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had no further questions on the matter and additional followup is not

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necessary, b.

Failure to update drawings to reflect safety injection accuation system (SIAS) modifications.

ONE Form FX-90-1235 was issued on March 15, 1990, ideitifying that the nuclear steam supply system (NSSS) vendor drawings for SIAS did not reflect a " Mode 5/6" switch installed to prevent inadvertent

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I safeguard actuations by disabling initiation-features not required by plant Technical Specifications when in Modes 5 or 6.

The licensee's

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the NSSS interface, in that the switch modification was engineered on site and had to be incorporated into the NS$$ configuration management system to achieve the vendor drawing revisions.

Normally, an NSS$ modification would be engineered by the NSSS vendor and drawing changes would be an internal-NSSS vendor activity.. The ONE

form documented adequate review of the specific problem, audit of design output documents and drawings for similar errors, and

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corrective actions responsive to the identified discrepancies. The licensee's overall actions appeared to the team to be acceptable.

The team had no further questions on this matter and additional

followup is not necessary.

c.

Control and use of operations department " lessons learned" documents'.

Operations department " lessons learned" material traditionally had been provided to plant operators, then filed and not presented to new personnel unless it was incorporated in another permanent document such as a procedure change or training lesson.. Operation department Administration Procedure ODA-106, " Review of Documents and Operational Feedback," Revision 5, Section 6.5.8.4, was changed to include transfer of information.to the training department for incorporation into both. requalification and initial operator training. The team also reviewed the. training center. activities-which evaluated and incorporated " lessons learned" material into the training program and found that it was effective in ensuring that

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pertinent material was linked with and incorporated into the appropriate lesson material.

The inspector had no further questions on this matter and additional followup is not necessary, d.

Licensee actions to further reduce the potential for reccurrence.

The team found that the licensee's evaluation and followup to ONE Form FX-90-1211 documented the actions planned and taken to date for the overall inadvertent safety injection event.

Action'

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notification (AN) forms had been issued to track individual action assignments. The licensee's evaluation had concluded that the event had been initiated by a random failure of a safety injection system actuation system diode, and the license had taken nine specific actions prior to plant heatup.

These included failed circuit. card

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testing and replacement, test procedure revision to include periodic testing of the failed diode, and provisions to block radiation

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monitor trip signals during routine testing.

The licensee had identified an additional 12 categories.of corrective actions for other deficiencies found during the evaluation.

These are also being tracked for completion and were confirmed by the team to be in acceptable status for continued plant operation. The team identified

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The team found

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the licensee's actions to be acceptable and additional followup is not necessary.

The followup showed that the licensee had adequately addressed these

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issues. No issues that impact operation above 50 percent were identified.

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6.

Maintenance Observations (93806)

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The objective of this portion of the assessment was to evaluate the licensee's controls for performing maintenance and modifications activities and determine if there were any concerns within this area that would impact negatively on safe power ascension above the 50 percent level.

To determine if the licensee's maintenance process was capable of supporting plant operations above 50 percent power, the team toured the maintenance facilities (electrical, mechanical, and ILC), reviewed administrative and control procedures, reviewed completed work packages, observed performance of maintenance activities in the field, discussed maintenance activities in the field, and discussed maintenance activities with appropriate personnel.

The team concluded that the licensee has established a maintenance organization with a capable and dedicated staff and appropriate procedures to effectively control and implement maintenance activities and to support plant operation above 50 percent power. The maintenance staff. supports

operation of the plant 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, 7 days a week.

The maintenance facilities, including the mechanical and test equipment

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laboratory and the meter and relay facility, are of good quality and are located close to the power block. The licensee has enhanced the maintenance program with the addition of a computerized drawing system that provides maintenance personnel with up-to-date drawings from a computer terminal located in each area.

In additior.. the licensee has installed a computerized surrogate plant tour system that provides a video display of all plant areas which is also available on a computer terminal in each area.

The team considered the inclusion of dedicated technical support (engineering), planning, and scheduling functions in each of the maintenance disciplines to be a strength.

The maintenance department had performed a self-assessment of maintenance activities and was in the process of evaluating the findings at the time of NRC's team assessment. The self-assessment process was based on INPO

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criteria and NRC maintenance team inspection guidelines.

The licensee's technical support preventive maintenance (PM) group consists of Il people dedicated to establishing, coordinating, and

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implementing the preventive maintenance program.

Procedure STA-677,

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" Preventive Maintenance Program," delineates the requirements and controls

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associated with this program.

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Once a week, delinquent PM tasks are reviewed by plant management at a ".

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backlog meeting. This provides plant management an awareness of overdue

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PM activities in their area-and visibility which would appear to encourage a corrective action.. Delinquent PM tasks require that tech S al evaluations i

be performed by the responsible work group, using the guidelines in

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STA-503, " Plant Incident Report.".This technical evaluation is forwarded c

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to the technica1' support group for evaluation and tracking. Approximately l

400-500 PM tasks are performed each month on Unit 1 and on equipment

u common to Units 1 and 2.

The maintenance backlog' indicated total-overdue

and delinquent PM tasks at 68 for the week of May 21-27, 1990, Of these i

68 tasks, 15 were delinquent.

From March 4-27, 1990, there was a high of;e

~ t 77 overdue PM tasks and a low of 36 overdue PM tasks, with a high;of'

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15 delinquent PM tasks and a low of 2 delinquent PM tasks." The team did

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not consider the number of overdue and delinquent PM tasks to be 'et a

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level that could impact plant safety or escalation of Unit 1 aboy'e,

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50 percent power, i

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The PM program is a part of the managed maintenance computer program (MMCP).

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The computer reviews all PM. tasks twice a week'and transfers those-that are coming due for performance to a file' that is reviewed by a responsible

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work group planner.

The planner schedules the PM and initiates,the

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appropriate instructions for' performing it.

During this: inspection, the

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licensee was considering initiation of a PM improvement program that would

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Improvement would be primarily through the elimination of unnecessary PM tasks.

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Theteamreviewedthelicensee'smaintenancebacklogindicaEorsforCPSES, Unit 1, and.oimon for the week of May 21-27, 1990, and discussed the

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backlog of corrective action 4tems with maintenance management and other

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cognizant licensee personnel.

Licensee maintenance management stated that the backlog was at a manageable level that would not i;npact the performance

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of corrective actions necessary to support power operations of Unit 1.

l The team agreed that the number of backlogged maintenance items did>not'.

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g appear to be at an unmanageable level that would impact on safe'opefation

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of the plant.

The licensee has established Procedure STA-606, " Work Requests' and Work Orders," to prescribe the methods and assign the responsibilities-for the work process used at CPSES. Both safety and nonsafety-related maintenancer activities are performed under the controls deline'ated in STA-606.

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primary difference between safety-and nonsafety-related maintenance

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appeared to be that the quality control organization is not involved in the nonsofety-related maintenance process.

However, the same work request and WO forms are used for procassing both activities and the maintenance is" planned, supervised, and performed by the same individuals who do the safety-related maintenance.

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The team reviewed completed documents and observed selected station

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maintenance ~ activities (both safety-and nonsafety-related) to verify that maintenance is conducted in accordance with the applicable procedures and

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• requirements. ~The. team reviewed completetf maintenance W0s~and observed portions of maintenance activities in-the field.

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In' gene'ral,-the team felt that work instructions provided to the field

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were of good quality, and craft. documentation-in the-WO provided an-s

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accurate record.of the maintenance performed.

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'The licensee has implemented a W0. format-that appears to be' conducive to-i s

accurate documentation in that it requires checking and recording of any T

required supporting documents (i.e., radiation work permits and clearances).

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iIn designatri areas on the W0s, the maintenance performer is also required

to 'docure - t. the as-found condition, the corrective action taken..the.

as-left W tion, and tha r* bable cause.of problem _ failure.

However, s

. the documentation in WO Mi#dN921, Revision- 0 (Train A motor-driven -

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auxiliary feedwater flow e*; rollers spuriously trip' to automatic),; was not cle' arias: to whether a"i; the problems identified in that documentation

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had been resolved. 'A-team member determined, from discussions'with

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t licensee instrumentation and control personnel, that the-problems had been

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' resolved byJa subsequert design modification installed on WO C900002263.

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The team observed that more information in the documentation could have provided a clearer understanding.of actual conditions and would not have

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left the impression that all=the problems identified had'not been addressed.

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.-The licensee's, implementation of their maintenance program was good. No issues were identified that_ impact operation above 50 percent power, i

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Startup Testing' (93806)

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The objective _ of th$s portion of the assessment was to review the status

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of tcompletion"of Unit l'startup tests and evaluate the effectiveness of

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the licensee's controls over testing to determine if there were any-concerns that may impact on safe power ascension above 50 percent or'which

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represented noncompliance with'NRC requirements.

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The team reviewed (he'startup test schedule and compared it to the irequirements identified in the-Final. Safety Analysis Report (FSAR). The i

scheduled testing appeared to meet all commitments addressed'in the FSAR.

No major test deferrals have occurred during testing.

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The Nam reviewed the following completed-or partially completed procedures

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.to: verify thaththe-test met the addressed requirements in the FSAR:

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Number Revision Title i

lISU-024A

RCS Flow Coastdown Test

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NUC-120 0.

Rod Swap Measurements

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ISU-101A

Initial Criticality and Low Power Test Sequence ISU-222A

'4 Turbine Generator Trip with Coincident Loss of.

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The team's review of the procedures determined that all acceptance

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criteria were achieved during performance of the tests.

Performance of the~

procedures was properly documented and procedures received'all reviews-

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required., Startup test logs properly documented performance of the tests.

The startup test program appeared to the team to be adequate to meet required commitments.

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No violations or deviations,were identified in this area.

No issies'were

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identified which impact operation above 50 percent-power.

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Surveillance --(93806) '

t The objective of this portion of the assessment was to evaluate the adequacy of the licensee's performance of Technical Specification surveillances through review and assessment of schedules,-ongoing

_i surveillances, injerdepartmental communications, and procedure adequacy

and compliance.

The team cc:q ared the Technical ' Specifications with the ma' ster surveillance testlist(MSTL)'.- All Technical Specification-required surveillances:were-cross-referenced toiprocedures innthe MSTL'.

The team sampled referenced

procedures and verif.ied that testing-was performed as required by Technical

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Specification..The, alternate flow path from the. boric acid tanks, via e gravity feed connection and a charging pump to the RCS specified in Technical Specification 3.1.2.2.a was not tested. Discussions with the

licensee revealed that a technica_1 evaluation had.been performed concerning

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the Technical Specification requirement..and that it was determined that

this 'iMw path would not be required except in very unusual circumstances.

The licensee stated that this was' recognized in abnormal operating

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procedures. The team determined that the Technical Specifications were

-being met and adequate controls were in place.

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The team' reviewed the licensee's method of scheduling, surveillances. The licensee has placed all required surveillances into the managed

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maintenance computer ' program <

Each department utilizes this program to schedule' s'urveillan'ces.

In addition, the surveillance test coordinator does a second check of required surveillances to verify that none are-missed.

The program appears to be adequate for' frequency dependent surveillances but the prooram for conditional surveillances has not.been j

fully effective.

No frequency-related surveillances have been performed

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out of the Technical Specification-required _ timeframe; however, three

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conditional surveillances have been' missed.

Licensee management has

' identified the late surveillances and appears to be taking adequate.

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corrective actions.

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On May 30, 1990, the inspector observed the performance of OPT-214A,-

" Diesel Generator Operability Test," Revision 4.

The operator performing

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I the test was knowledgeable of all test requirements. The procedure L

appeared.to-be very cumbersome, as demonstrated by the diesel running for

36 minutes prior to loading. During the performance of the procedure, the unitLsupervisor entered N/A for a step requiring notification of the-

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dispatcher and approved performing steps out of order in the procedure l

(loading the diesel prior to completing. independent verification of the-position of air receiver' outlet valves and start circuit breakers).

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inspector believes that these steps do not. technically affect the performance of the procedure and discussions with the unit. supervisor determined tnat he, administrative 1y, is allowed to perform these actions.

Aichough changing these steps would improve the procedure by eliminating-the necessity for these decisions, no action was taken to initiate a procedure change. However, when the inspector pointed out to the operator a typographical error in the procedure which,.under certain circumstances, i

could prevent the procedure from.being performed correctly, steps were immediately taken to perform a procedure change.

Subsequent discussions with licensee management revealed that mechanisms, in accordance with ODA-407,'" Guideline on use of Procedure," exist for operations department personnel to initiate procedure changes.

Th'e licensee has recently reemphasized to the operations department _the necessity to initiate procedure changes to improve existing procedures.

In addition, two qualified unit supervisors were recently assigned the specific task of reviewing and changing, as required, operations department procedures.

The-inspector reviewed EGT-712A, " Reactor Coolant System Boundary Isolation Valve Leakage Testing," Revision 5.

The procedure was divided into several paragraphs, each with its own set of-prerequisites, each of which tested several valves. The procedure was 153 pages long and-in parts difficult to follow. There were many steps which had to be repeated and,-in some instances, the repeated steps directed'the test performer _to skip other steps. The procedure,-in addition, contained a note in paragraph 11.7, which stated " Steps 11.7.1 - 11.7.5 may be performed in

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any sequence." Step 11,7.1 verifies that prerequisites are met; other>

steps in.the sequence operate valves.

This could potentially allow valve operation prior to prerequisite performance. The procedure, in places, t

did not provide proper directions concerning contingencies'within the procedure.

For example, directions were given to equalize and isolate a flow detector. Subsequently, the procedure directed unisolating the i

detector when flow was less that 1 gpm, but to leave it isolated if flow was greater than 1 gpm.

ie procedure went on apparently assuming flow

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was less that 1 gpm, because a subseq'uent step repeated equalizing and isolating the flow detector. The inspector-discussed the above concerns with test engineers from the performance and test department.

The engineers stated that they had informally discussed breaking down EGT-712A into several separate procedures but were unaware of definite plans to do so.

In addition, the engineers stated that they always verified prerequisites prior to performing any steps of a procedure.

Concerning-contingency step problems, they stated that whether they would N/A the steps as written or change the procedure would depend on the actual t

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engineers did not state'that they would change the procedure or admit that-

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any problems existed with the procedure.

Subsequently, the licensee

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provided the team'with a matrix dated May 28, 1990, that showed that-

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several complicated surveillance procedures _were being separated linto smaller procedures.

EGT-712A was among the procedures: listed in thel matrix as being separated into several smaller procedures.

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No violations or deviations were identified in this area. The surveillance procedures, in many cases, appeared to be cumbersome and-difficult to work with which could present problems in the future. The:

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mechanisms for procedure improvement differ imong departments and

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these mechanisms have not been fully effect' e.t The program for scheduling frequency dependent surveillances was adequate, however, the scheduling of contingency.surveillances has not prevented the late performance of three surveillances, No-issues ~were identified that impact operation'above 50 percent power,

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Program for Problem Identification, Reporting, and Resolution = (93806)

The team reviewed the licensee's-process for evaluating-deficienc'ies or

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adverse conditions identified by employees and contractors.

The process is documented in Procedures STA-421 and STA-422, the latter of which describes the requirements for the administration, screening for operability and reportability, identification of corrective action _ type i

resolution, and closure of potential adverse conditions identified on 0NE-forms.

STA-421, " Operations Notification and-Evaluation (ONE) Form," and STA-422,-

" Processing of Operations Notification and Evaluation (ONE) Forms,!' require that personnel who identify potentially adverse conditions _ notify the

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l shift _ supervisor-via the use of_the ONE form. _To-ensure that personnel are aware of their responsibilities, the. licensee provides. training to all

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For those t

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personnel who were already badged when the 0NELprogram:was initiated, a

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memorandum was issued on January 16, 1990, to notify-these: personnel of the existence of the program and-their responsibilities.

During review of ONE. Form FX-90-1614, datec May 23, 1990,.the team noted that the form identified a' tornado damSm that did not appear to comply.

with the requirements for-a security v. cal area barrier,D This potential security problem was not forwarded to the security shift supervisor until May 25, 1990, when the work control center (WCC) received the ONE' form. -

Th?refore, information about a potentially inadequate security vital area

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barrier was available for approximately 1 to 2 days before-security. was

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notified. -Final resolution of the apparent discrepancy indicated that the

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tornado damper was an adequate vital area barrier.

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The requirements in STA-422 state that the WCC~will notify security of any security problems identified on ONE forms. As demonstrated above, this notification may not be timely and is considered to be a procedural

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During review of STA-504, " Technical Evaluati_ons," the. team noted that' no

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requirements exist that direct the preparer of a technical evaluation to-verify that the-problem documented on the ONE' form does not affeet the '

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design: basis (e,g, FSAR,: design basis documents,- etc.) of.the plant.-

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' During review of ONE forms, the team noted that technical evaluations did

not. regularly address the affect.on the design basis. The team did not t

identify any problems in this area; however, the-team felt that'a i'

requirement'added to STA-504 for review of;the design basis would strengthen the program.- The licensee-stated that it would perform a;

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review to determine if the requirement should be-added to the procedure.

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The technical evaluations reviewed by the team appeared to contain the-

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necessary data and information to support the conclusion (s) documented in the technical evaluations.

The team reviewed STA-515, " Root Cause ' Analysis," and_ noted that it appeared to establish an adequate program for the preparation and. issuance of root-cause analyses.

STA-422 requires that all ONE forms classified as_ plant incidents receive a root cause analysis.

STA-422 defines a plant incident as a n gnificant variation from normal plant operations or equipment performance;that isiof

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interest to plant -management..- As a minimum, this includes incidents that

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may require a report to.a regulatory agency.

This approach by'licensec management appears to be adequate in that the issuance of root-cause:

analyses for plant incidents.should provide management with the

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appropriate data for identifying and correcting incident. causal; factors, i

Thir approach is dependent, however, on the licensee's' ability.to

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adequately classify problems. identified on ONE forms as plant incidents.

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During review of ONE forms by the team, no concerns were noted with the

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licensee's classification of problems as plant incidents.-

The team reviewed the root-cause analyses that had been issued for ONE'

Forms FX-90-930, FX-90-1173, FX-90-1239, FX-90-1366, and FX-90-1487. The team identified no concerns during review of the analyses.

It appeared that the licensee had identified the root ~ causes,. determined the corrective actions to be;taken, and-had implemented, or was in the process of, implementing the corrective actions.

A review of the ONE forms generated.since February 9, 1990, indicated that

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the forms-identified potential problems in a variety of areas.

Since February 9,1990, approximately 700 ONE forms have been ger.erated.. Based

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on this review, it appeared that the ONE form program is effectively functioning for problem identification, since personnel in various site organizations were generating the ONE forms.and the volume of forms was

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high.

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The team reviewed a sample of ONE forms for operability and reportability determinations.

Except for the concern discussed below, the operability

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and reporta'.>ility determinations were found to be adequate.

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During review of ONE Forms FX-90-1110 and FX-90-1464, the team noted that some confusion existed with respect to the reportability requirements for a significant loss of emergency assessment capabilities, as required by 10CFR"Part50.72(b)(1)(v)..In one case, the emergency notification system (ENS) telephone was lost and it was reported, based on a determination by the licensing organization. The shift supervisor did not feel that the loss of the ENS telephone was reportable.

In another case,.the licensee' lost power and telephone lines to the.

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emergency offsite facility (EOF), causing' a' reduction in' the licensee's capability to~ assess an accident from the. EOF.

This incident was not reported.

This nonconservative performance is considered to be attributable to a weakness.in the directions provided in STA-501, i

"Nonroutine Reporting." ' Consequently, the licensee has initiated a change y

to t6e procedure to provide clarificationLto:the operations shift j

supervisors on what. constitutes a'significant. loss of assessment capabilities to-ensure that decisions to report events.to the NRC are made in a conservative fashion.

ONE Forms FX-90-1210, FX-90-1295, FX-90-1558, and FX-90-1609 documented potential: problems where the-shift supervisor could not determine system and/or component operability due to the need for ' engineering to. evaluate the data provided on the form. The team noted that, in each case, engineering perfor:ned a timely review of the data to determine system-and/or component operability. The results.of the engineering evaluation -

were provided to the shif t supervisor so that the.necessary actions could i

be taken, as appropriate.

The licensee's implementation of the ONE form program appeared >to provide t

for the proper prioritization for implerrantation of. actions for potential problems identified. A team member attended'a ONE. form meeting,-held each workday morning by the licensee, and no:ed that system and/or component operability was immediately consMered and that safety-significant items

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were being addressed in a timely mannat.

The time provided for response-

to potential safety issues appeared to be appropriate based-on the-i significance of the issue.

The team reviewed the corrective actions'specified on ONE form evaluations and responses to verify that the actions were appropriate and were being,

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implemented in a timely manner. Based on the ONE forms reviewed by the team, it appeared that the licensee was identifying the appropriate corrective actions and that the' actions, with respect to-safety

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significance, were being' implemented in a timely manner.

As of May 28, 1990, the licensee had 187 ONE forms that had not been closed.

The same approximate total number of ONE forms has been op'en over the past few months.

Considering the amount of ONE forms being generated, m

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this. level of open forms did not-appear-to be excessive, since.the team verified that the most safety-significant' potential' problems are being addressed in a timely manner.:

During review of the ONE form = program, the team noted that'the'. licensee's

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quality. assurance _orgai:ization routinely reviews the data provided on ONE

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forms and issues a trend Ng report to indicate the types of problems

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being identified on O'.a. fons. The data from the ONE forms, together with data;from other programs that-identify. deficient; conditions

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(e.g., nonconformance roorts and deficiencies), are compiled as-input:

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into trending reports.. These reports are routinely provided to management-and serve as a tool for'. management to identify areas where additional-l

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attention and oversight may be required.

In NRC Inspection' Report 50-445/90-14; 50-446/90-14, a concern was

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identified in that a charter did.not exist for the group of individuals that meet each workday morning'to review ONE forms. = The. licensee revised-

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STA-422 to specify.which site organizations are required to have a'

M representative at the ONE form-meeting and.which individual was to chair the review group.

It appeared to the team that the licenseo adequatkly addressed'the concern.

Overall, the licensee appears:to be implementing a satisfactory program-

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Although the team identified some apparent weaknesses in the ' program, the

weaknesses did not indicate a programmatic breakdown in the implementation of the ONE form process, since the weaknesses had very. minor _ safety-

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significance.

However, the licensee should take. actions to correctthe

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weaknesses in a timely manner. No issues.were identified that impact

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operation above 50 percent power.

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Review of Licensee's Self-Assessment (93806)

On June 14, 1990,- the team leader, NRC Region ~.IV managers, and NRR managers reviewed the licensee's procedu're'for conducting their-self-assessment (STA-TP-89A-2); the detailed results of the licensee

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self-assessment; and the June 13, 1990, letter from William J.~ Cahill, Jr.,

l-to Robert D. Martin concerning the readiness of CPSES to proceed beyond 50 percent power.

In conducting this review, the NRC considered the.

results since fuel load of NRC inspections, enforcement actions 'taken,. and plant events.

The review showed

..at the licensee's self-assessment was= generally in

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agreement with the results of the NRC inspections. The NRC concluded that

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the CPSES equipment, progress, and personnel performance was adequate and -

that the startup testing program could safely proceed:above 50 percent-power.

This conclusion was transmitted to the licensee by letter-dated June 15, 1990, from Robert D. Martin to William J. Cahill, Jr.

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-30-11. ' Exit Meeting'

- An exit meting was conducted on June 15, 1990, with the applicant's-.

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representatives identified.in paragraph 1 of.this report. The applicant did not identify as proprietary any of.the materials provided to, or reviewed by,-the inspectors during-this inspection. During this meeting',

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the team leader summarized the scope and findings of the_ inspection.

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