ML20059M529

Applicant Exhibits A-21,A-22,A-24,A-25,A-26,A-29 & A-F1, Consisting of Related Correspondence Not Admitted Into Evidence.Related Correspondence

ML20059M529
Person / Time
Site:	Diablo Canyon
Issue date:	11/19/1993
From:	PACIFIC GAS & ELECTRIC CO.
To:
References
CON-#493-14434 OLA-2, NUDOCS 9311190146
Download: ML20059M529 (100)

Text

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hild Onsite Safety Review Group (0SRG)

February 1993 Monthly Report

'93 03 28 P 6 $6 The following items summarize the OSRG's observations and concerns.from the meetings for this month. A more detailed description follows, and all items'that were reviewed are listed in Attachment 1.

1.

The OSRG revisited unresolved precursor events outlined in the January minutes.

Several potential corrective actions to prevent recurrence were

. proposed.

2.

The OSRG reviewed the design for a manual isolation valve on the discharge of the positive displacement charging pump (PDP) relief valve.

The administrative controls also were reviewed to ensure that the isolation valve is open whenever the PDP is operating or available for service.

The design was referred to QA for follow-up regarding compliance with applicable codes and standards.

3.

The OSRG reviewed the current compensatory action of maintaining one containment fan cooler unit (CFCU) out of service (005) in each of DCPP Units 1 & 2.

The choice of CFCUs 1-3 and 2-3 was concurred with.

It was noted that CFCUs 1-2 and 2-2 might be slightly better than the current choices, from a redundancy standpoint.

4.

The ASW pump 4kV feeder cable failures were reviewed with regard to the high

'i failure rate.

The TRG seemed to be addressing all nuclear safety aspects adequately.

5.

In reviewing a recent NOV, the OSRG identified a potential generic concern with inappropriate painting.

The NOV involved painting over the blue dots used for locating vibration test points on plant equipment.

DESCRIPTION The following items were discussed by the OSRG.

Generally, where concerns exist, they have been discussed with the appropriate TRG Chairman or responsible department l

head and an AR has been initiated, if applicable.

1.

OSRG Surveillance 92-061:

Inadequate Corrective Actions for Precursors to Recent NCRs and QEs CONCERN: The OSRG identified a concern in its January 1993 minutes regarding inadequate response to certain precursor events.

The precursor events did not receive adequate corrective actions. Therefore, they recurred later in a form serious enough to warrant an NCR or QE.

The items that were cited included 9311190146 931119 PDR ADOCK 05000275-O PDR

3.

OSRG Surveillance 93-003:

CFCUs 1-3 and 2-3-Removed From Service OBSERVATION:

The OSRG reviewed the CFCU configuration that currently is in We concur with CFCUs 1-3 and 2-3 being kept out of service. Also, it use.

was noted that it might be slightly better if CFCUs l_2 and 2-2 were removed from service rather than 1-3 and 2-3.

This was based on redundancy of components.

DISCUSSION:

CFCUs 1-3 and 2-3 have been removed from service as a temporary compensatory measure for Operability Evaluation 93-02.

The purpose is to preclude a hypothesized overheating of the CCW system during a design basis large break LOCA.

The OSRG reviewed the current configuration for redundancy. A matrix was developed for the CFCUs in relation to their associated SSPS train, CCW vital header, and electrical bus (see below).

From this matrix it appe ared that if a failure of CCW header B were to occur, in the current configuration, only one CFCU would remain operable. The FSAR analysis assumes two CFCUs remain operable.

The OSRG engineer then analyzed if there was a credible failure of CCW header B.

Nothing credible could be hypothesized.

Therefore, the OSRG had no objection to the current practice.

r CFCU 1

2 3

4 l

5 SSPS A (K608)

A (K609)

A (K609)

B (K608)

B (K609)

B (K609)

CCW A

A HDR B

B B

~ BUS F

F G

H G

Note:

Removing CFCU 1-2/2-2 from service would retain the greatest degree of redundancy.

4.

DCl-92-EM-N054:

High Potential (Hi-pot) Test on ASW Pump Motor 1-2 4kV Failed Cable CONCERN: The OSRG reviewed earlier concerns (November 1992 Monthly Report) regarding the higher-than-expected failure rate of ASW pump 4kV motor cables during Hi-pot testing.

The failure mechanism, potential reportability and operability were discussed.

_ ~. - _--..

RESOLUTION: The OSRG concluded that, to date, the TRG was addressing generic issues adequately, in addition, the issues have a high degree of management attention in the form of an Integrated Problem Response Team (IPRT).

The OSRG will continue to monitor further PG&E investigations into the cable failures.

DISCUSSION: ASW pump 1-2 was removed from service for repairs. When returning the ASW pump to service, a direct current Hi-pot test was conducted.

During the test, the insulation broke down. All three phases of cable were replaced between the 12kV switchgear room and the discharge structure.

While replacing the three power cables, water was discovered in an ASW 1-2 pull box.

It is speculated that a storm a few days before the Hi-pot test was the source of the water. The DCPP cables are not designed for continuous submergence.

These ASW pump cables may have been pulled through conduit several times.

Both this failure and an earlier failure on Unit 2 occurred at approximately the same location in the conduit runs. Therefore, there could be an installation-related failure mechanism.

As investigative actions, PG&E will have the following tests performed:

1.

partial discharge 15kV corona testing 2.

power factor testing 3.

ac/dc withstand testing 4.

insulation resistance testing 5.

ac breakdown testing 6.

physical testing (tensile and elongation) 7.

dissection of the area with the fault Initial inspections of the cable by PG&E showed that the overall physical and electrical condition was good. There was no obvious sign of a failure mechanism.

The exact failure mechanism for the earlier 1989 ASW pump motor cable also could not be determined. The failure was not considered generic to the cable manufacturing processes used in 1972 by Okonite.

Per Okonite, the neoprene jacket on the cable that failed in 1989 had aged as expected. All other properties met specifications.

There were no significant differences between the cables tested and the properties reported in the 1972 test reports other than the neoprene jacket.

Examination of the conductors showed that there was no significant amount of moisture in the conductor for any appreciable length of time.

Each length was subjected to factory electrical tests. All lengths passed.

Okonite stated that electrically and physically the insulation was in "as new" condition.

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.r t!uclea' Peaer GNatcQ Darember 14, 1992 PC&E Letter No. DCL 92-275 U.S. Nuclear Regulatory Cumission ATTN: Document Control Desk Washington, D.C.

20555 Re:

Docket No. 50-275, OL-DPR-80 Docket No. 50-323. OL-DPR-82 Diablo Canyon Units 1 and 2 Reply to Notice of Violation in NRC Inspection Report 50-275/92-26 and 50-323/92-26 Gentlemen:

NRC Inspection Report 50-275/92-26 and 50-323/92-26, dated November 13, 1992, cited one severity Level IV violation regarding PC&E's radiation protection program. PG&E's response to the Notice of violatinn is enclosed.

Sincerely, 1

1 Gr,egory H. Rueger

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Ann P. Hudgdon 1

John B. Hartin Mary H. Miller Sheri R. Peterson CPUC Diablo llistribution DCl-92-HP-N060 Enclosure 10805/85K/PSN/223~/

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AUG 19 '90 12:50 FROM PG E-NRS TO 919055414302 PAGE.000/005 PG&E Letter No. DCL-92-275 ENCLOSURE m

REPLY TO NOTICE OF VIOLATION IN NRC INSPECTION REPORT 50-275/92-26 AND 50-323/92-26 On November 13, 1992, as part of NRC Inspection Report 50-275/92-26 and 50-323/92-26, NRC Region V issued a Notice of Violation (NOV) citing one Severity Level IV violation for Diablo Canyon Power Plant (OCPP) Units 1 and 2.

The statement of violation and PG&E's response follow.

STATEMENT OF VIOLATION Technical Specification 6.8.1 requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1978.

RG 1.33, Appendix A lists, in part, the following procedures:

7.

Procedures for Control of Radioactivity (For limiting materials released to environment and limiting personnel

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exposure) e.

Radiation Protection Procedures (3)

Airborne Radioactivity Monitoring (4)

Contamination Control Licensee Procedure MRS-2.4.2-GEN 38 (Steam Generator Shot Peening Procedure), Section 9.7.13.5.2, established September 27, 1992, applied certain rules in order to control airborne radioactivity and contamination.

These rules required that, with ventilation interrupted to the steam generator cold leg for longer than 15 minutes, either:

i 1

1.

Shot peening could be temporarily terminated, or 2.

With ventilation switched from the cold leg to the hot leg, and dry air supply switched from the hot leg to the cold leg, shot peening could continue.

Contrary to the above, on October 2, 1992, eddy current and shot peening operators failed to implement the m

provisions for control of radioactivity as given in MRS-2.4.2-GEN 38, Section 9.7.13.5.2, in that ventilation

AUG 19 '93 12:50 FROM PG E-NRS TO 918055414302 PAGE.004/005 was interrupted to the steam generator cold leg for one m

hour, and shot peening continued without switching of the ventilation and dry air supply as required. This failure to implement the procedure resulted in the unanticipated spread of airborne radioactivity.

This is a Severity level IV violation (Supplement IV).

REASON FOR THE VIOLATION PG&E agrees with the violation.

To provide humidity control for sbat peening work performed in the steam generator (SG) hot leg, dry air is blown into the hot leg manway. An additional source of pressurizing air is the shot peening equipment itself.

To maintain control of any loose contamination within the SG, a negative j

pressure is maintained within the SG by drawing air out from the cold leg manway through a high efficiency particulate airborne (HEPA) filter.

The personnel contracted'to perform the shot peening work controlled the hot leg dry air supply for humidity control.

Prior to beginning work, these individuals were trained on the significance of the ventilation system in maintaining negative pressure in the SG.

However, the contract personnel responsible for eddy current testing and tube i

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plugging on the cold leg side of the SG were accustomed to HEPA suction on the opposite leg (hot leg) from their work.

These individuals were not specifically trained on the new configuration of the SG ventilation for shot peening (i.e., HEPA suction on the cold leg) prior to beginning work in the cold leg.

The cover letter that transmitted the NOV and NRC Inspection Report 50-275/92-26 and 50-323/92-26 noted that PG&E's overall control of radiological hazards encountered during SG work in the Unit 1 outage appeared to be exemplary.

However, the Inspection Report identified a concern regarding recurrent unanticipated generation of airborne radioactivity, since two previous, related events occurred on September 25 and 26, 1992.

On September 25, 1992, there was an increase in contamination in the posted hot particle zone surrounding SG l-1.

The cold leg manway door was opened for i

approximately one minute and it is postulated that loose contamination within i

the SG was blown onto the platfom and down to the lower work areas.

Although i

contamination levels increased within the crane wall area, no increase in activity occurred outside the crane wall.

It should be noted that the discharge from the HEPA filters was directed across a highly contaminated trough, and it was not determined whether the spread of contamination was due to the opening of the cold leg manway door or the HEPA air discharge blowing across the contaminated trough.

Corrective actions were to reposition the HEPA discharge, provide additional step-by-step instructions for removing cold leg ventilation, and review this information with the involved personnel.

n On September 26, 1992, the SG l-3 cold leg manway door was opened for eddy current maintenance. A dry air supply valve to the hot leg was either not i

AUG 19 '93 12:51 FRott P3 E-NR$

To 918055414302 PAGE.005e005 f

shut off all the way, or the valve was bumped open after it was shut. An airborne radiation monitor alarmed, and other airborne monitors inside contelnment were also reading upscale. The imediate corrective actions were to notify the control room and evacuate cuot4inment, formalize a checklist for oddy current personnel breaching the manway, and instruct shot peening personnel to stop shot peening if the cold leg manway door remained open for longer than 15 minutes. Personnel were tailboarded prior to resuming work.

On October 2, 1992, the event that is the subject of the NOV occurred.

Personnel working in the cold leg opened the cold leg menw4y door and stepped HEPA suction and dry air supply to SG l-4 for approximately one hour without stopping shot peening in the hot leg as directed in the new guidance added after the September 26, 1992 cvent. This caused an airborne radio 4ctivity monitor to alarm.

PG&E agrees with the NRC that the corrective actions identified for the first two events were adequate and would have prevented the third event if they had been effectively implemented. In additlun, PG&E's analysis of all three events enneluded that the root cause of the cycnts was that no overall responsibility was established for proper operation of the SG ventilation system to support (a) shot peening activities in the hot leg and (b) eddy current testing / tube plugging activities in the cold leg.

A contributing factor waa th4L the personnel working on the r.nld leg side were not well trained on the ventilation requirements. The corrective actions taken after the first two events addressed only part of this overall programatic root cause.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEYED After the October 2,1992 event, shot peening work was stopped and a tailboard meeting was held to critique the event. The dry air supply and HEPA suction were switched so that HEPA suction was now on the hot leg, thereby allowing easier access to work in the cold leg. The shot penning shift supervisor was given overall responsibility for SG breeches and SG ventilation. This responubility was added to the shot pcening procedure via a field change.

Shot peeniny work continued with a tailhoard at each shift change, and the work was completed with no further incidents.

CORRECTIVE STEPS THAT WILL BE TAXEN TO AVOID FURTHER VIOLATIONS Prior to the Unit 2 fifth refueling outage in the spring of 1993, the shot peening and eddy current testing procedures will be revised to permanently incorporate the field changes discussed above. Personnel involved in SG eddy current testing will be trained on the operation of the ventilation system and maintaining negative pressure.

4 DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED Based on the completed field changes to the procedure, PG&E is currently in

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full compliance.

The permanent procedure revisions and training of eddy current personnel will be completed by fiarch 1,1993.

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U.S. Nuclear Regulatory Commission if' 'O

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Document Control Desk Washington, D.C.

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Re:

Docket No. 50-275, OL-DPR-80

'O9 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 Reply to Notice of Violation in NRC Inspection Report 50-275/92-17 and 50-323/92-17_

Gentlemen:

NRC Inspection Report 50-275/92-17 and 50-323/92-17, dated contained a Notice of Violation citing three Severity June 19, 1992, Level IV violations regarding (1) work order instructions that were not implemented for maintenance of containment fan cooler units (CFCUs),

(2) an inspection of Unit 2 CFCUs that was conducted without appropriate procedures, and (3) untimely corrective action taken on a CFCU reverse rotation condition.

PG1E's response to the Notice of Violation is enclosed.

As discussed in meetings between NRC and PG&E on April 2 and L

PGiE considers these issues regarding improper CFCU May 19, 1992, maintenance to be significant and has implemented an extensive corrective action program to address them.

PG&E is committed to aggressive, comprehensive, and timely resolution of maintenance problems Our that may indicate conditions adverse to quality or safety.

corrective action program is intended to clearly communicate management's expectation that all employees will adhere to this commitment.

Sincerely,

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9 Gregory M. Rueger cc:

Ann P. Hodgdon John B. Martin Philip J. Morrill dt?- Z 73 [32 3 CC4 Harry Rood CPUC Diablo Distribution k

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.ON FOR THE VIOLATION 4E agrees with the violation.

/G1E has thoroughly investigated this event.

The investigative team included personnel from plant operations; system, maintenance, and design engineering; as well as the quality organizations.

Vendor information was also considered.

In addition, as discussed in meetings with the NRC on this subject, senior management has been extensively involved because it considers the improper CFCU maintenance to be significant and has directed that a thorough investigative and corrective action program be implemented.

The investigation team determined that the cause of the improperly assembled

'CFCU backdraft dampers was that management and the maintenance organization underestimated the importance of the backdraft damper to the overall safety

, function of the CFCUs, and therefore did not provide for adequate maintenance.

! This resulted in inadequate:

(1) planning of CFCU backdraft damper work; (2) work instructions; (3) job turnover; (4) Quality Control (QC) involvement in inspection of CFCU backdrait damper work; and (5) system engineer involvement.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED All ten Unit I and Unit 2 CFCUs have been thoroughly reinspected and all identified deficiencies have been repaired or evaluated by design and maintenance engineering and accepted.

The CFCUs have been tested to thoroughly demonstrate backdraft damper operability.

Surveillance Test Procedure (STP) M-51 A, " Routine Surveillance of Containment Fan Cooler Units for Reverse Rotation," is being performed on a monthly basis until all ten units are completely overhauled during the upcoming refueling outages IR5 and 2RS.

To corrett the inadequacies noted above, PG&E has formed a CFCU High Impact Team (HIT) to assure adequate planning and coordination of maintenance activities and identification of spare parts associated with backdraft damper overhaul planned for 1R5 and 2R5.

A nonconformance report (NCR DCO-92-MM-N007) was issued to determine the root cause and corrective actions necessary to resolve the immediate and long-term concerns.

A multi-disciplinary Integrated Problem Response Team (IPRT) was formed to investigate the conditions and to determine if the problem is symptomatic of larger problems.

l Also, to ensure that CFCU backdraft damper maintenance is conducted properly, post-maintenance testing procedure PMT 23.06, " Test of CFCU Backdraft Dampers," has been developed to specifically confirm CFCU backdraf t damper operability. As part of the review of this event, PG&E is surveying plant maintenance, operations, and technical support personnel 'to determine if there are other safety-related systems or components where appropriate practices, quality and/or understanding of the functions have not been clarified.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS STP M-93A, "CFCU Test," for backdraft dampers will be revised to adequately Maintenance verify backdraft damper operability following CFCU maintenance.

Procedure (MP) M-23.8 is being developed to provide more specific instructions for (fCU backdraft damper maintenance.

Maintenance personnel assigned to SS285/E5K -

S STATEMENT OF VIOLATION B Section 6.8.1 of the Diablo Canyon Technical Specifications requires the licensee to establish and implement procedures for the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, 1978.

Section 8.b of Appendix A to Regulatory Guide 1.33, Revision 2, states that appropriate procedures or instructions should be provided for the performance of inspections that can affect the performance of safety-related equipment.

Contrary to the above, the licensee's inspection of Unit 2 CFCUs on March 7 and 8, 1992 was conducted without appropriate procedures, and incorrectly concluded that CFCOs 2-2 and 2-5 were assembled correctly.

This is a Severity Level IV violation (Supplement I),

l applicable to Unit 2.

REASON FOR THE VIOLATION PG1E agrees with the violation.

PG&E's investigation of this issue included:

Interviews with the involved individuals by the Senior Mechanical Maintenance Engineer, Director - Mechanical Maintenance, Manager - Maintenance Services, and Senior Vice President and General Manager - Nuclear Power Generation Interviews with other involved supervisors and craft personnel e

A formal Human Performance Evaluation System evaluation j

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PGLE's investigation concluded that although the inspection instructions were oral, the engineers understood the inspection assignment and did, in fact, write down the results of their inspection activities following the inspection.

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to be filled out during the inspection activities.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED The individuals performing the inspection have been formally disciplined in accordance with the PG&E Positive Discipline Program which includes a formal letter to file and follow up evaluations of performance.

j To further emphasize management's expectations, a letter was issued to all employees within Nuclear Power Generation on May 18, 1992, by the Senior Vice President and General Manager - Nuclear Power Generation, which reemphasized 552ES!B5K STATEMENT OF VIOLATION C 10 CFR Part 50, Appendix B, Criterion XVI, requires that measures be es*ablished to assure that conditions adverse to quality, such as defective equipment, are corrected.

Contrary to the above, on March 27, 1991 until February 22, 1992, the licensee failed to correct a condition involving reverse rotation of CFCU 1-5, a condition adverse to quality. Correction of this problem could have led to the discovery of similar problems with the backdraft dampers associated with three other containment fan cooler units.

This is a Severity Level IV violation (Supplement I), applicable to Unit 1.

REASON FOR THE VIOLATION PG&E agrees with the violation.

PG&E believes that the cause of the untimely response to the identified CFCU reverse rotation problem was that ~^7~*

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Inadequate system engineering staffing levels also resulted in system engineering personnel being overburdened with other responsibilities.

These inadequate staffing levels resulted in missed I

opportunities to learn from prior problems and observations relative to backdraft damper design and maintenance.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED A multi-disciplinary Integrated Problem Response Team (IPRT) was formed to evaluate the organizational effectiveness in responding to the emerging CFCU issues in January through March 1992 (Task I of the IPRT Report, dated June 3,1992), and to evaluate the containment HVAC system to determine if there is an underlying root cause that has contributed to the history of identified CFCU problems (Task 2 of the IPRT Report, dated June 3,1992).

The IPRT concluded in Task 1 that the initial organizational response could have been more comprehensive and timely; however, the backdr, aft damper problems were pursued aggressively to resolution.

The IPRT concluded in Task 2 that there is no underlying physical root cause for the identified HVAC problems.

The IPRT concluded that the HVAC problems were attributable to inadequate design and maintenance.

A nonconformance report (NCR DCO-92-MM-N022) had been previously initiated to focus on maintenance practices, procedures, and methods associated with safety-related HVAC equipment.

The IPRT provided their recommendations to the Technical Review Group for their consideration in developing the final corrective actions for NCR DCO-92-MM-N007.

SE2E5/E5K

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To provide additional guidance in enhancing the quality, completeness, and consistency of engineering evaluations of degraded plant conditions, PG&E will revise Nuclear Plant Administrative Procedure (NPAP) C-29/ Nuclear Power Generation 7.10, " Operability Evaluation." Training will be provided for engineers, supervisors, and licensed operations personnel in evaluating degraded plant conditions.

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED PG&E is in full compliance with Appendix B Criterion XVI.

Corrective actions to be taken will be completed as follows:

1.

A Program Directive describing the responsiblities of the various engineering disciplines will be issued by December 31, 1992.

2.

QC inspection selection criteria will be revised by December 31, 1992.

3.

QC Department training on the requirement for thorough documentation will be completed by August 31, 1992.

4.

The six additional system engineering positions are scheduled to be staffed by December 31, 1992.

5.

NPAP C-29/NPG 7.10 will be revised by August 31, 1992.

I 6.

Training regarding degraded plant conditions will be completed by August 31, 1992 7.

The scope of work order review for inspection activities will be reassessed by August 31, 1992.

8.

Re-emphasis of management expectations of QA/QC will be completed by August 31, 1992.

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'93 [ EN3 June 6, 1988 PG&E Letter No. DCL-88-150 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk 1

Washington, D.C.

20555 l

l Re:

Docket No. 50-275, OL-DPR-80 Diablo Canyon Unit 1 Reply to a Notice of Violation in NRC Inspection Report No. 50-275/88-07 l

Gentlemen.

j NRC Inspection Report No. 50-275/88-07, dated May 5, 1988, contained a Notice of Violation applicable to Diablo Canyon Power Plant (DCPP)

Unit 1, citing two Severity Level IV violations and one Severity Level V violation regarding housekeeping, draining of accumulators, and data input to calculations.

PG&E's response to this Notice of Violation is provided in the enclosure.

The inspection report expressed an NRC concern with untimely plant staff actions in dealing with cleanliness problems.

As previously indicated in discussions with Region V and further discussed in the response to violation A in the enclosure, plant management is taking appropriate actions to ensure that plant cleanliness is maintained and that foreign material is prevented from inadvertently entering plant systems.

Kindly acknowledge receipt of this material on the enclosed copy of this letter and return it in the enclosed addressed envelope.

Sin erely, J. D. Shiffer cc:

J. B. Hartin H. H. Hendonca Na but qgg H. Rood l m NifMpec B. H. Vogler fQQ$$

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PG&E Letter No. DCL-88-150 T

ENCLOSURE RESPONSE TO NOTICE OF VIOLATION IN NRC INSPECTION REPORT NO.~50-275/88-07 On May 5, 1988, as part of NRC Inspection Report No. 50-275/88-07 (Inspection Report), NRC Region V issued a Notice of Violation applicable to Diablo Canyon Power Plant (DCPP) Unit 1, citing two Severity Level IV violations and one Severity Level V violation.

The statements of violation and PG&E's responses are as follows:

A.

STATEMENT OF VIOLATION 10 CFR 50, Appendix B, Criteria V, " Instructions, 4

Procedures, and Drawings" specifies, in part, " Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings."

In partial implementation of this requirement, Nuclear Power Generation Department Administrative Procedure NPAP C-10, " Housekeeping - General,"

Section 4.4.1.c.l(b), specifies for Zone 3 (tool control) housekeeping areas, "all tools, equipment, pencils and other articles which are brought into the area shall be logged in and out."

Contrary to the above, on April 14, 1988, a Zone 3 housekeeping area, established for the Unit I reactor vessel head cable tray area, was found to contain loose tools (such as a pocket knife, cutting blade, and open allen wrench set) which were not entered on the provided log.

l This is a Severity Level V violation (Supplement I) applicable to Unit 1.

REASON FOR THE VIOLATION IF ADMITTED PG&E acknowledges that the violation occurred as described in the Inspection Report due to insufficient attention to cleanliness control requirements by l

supervision and craftsmen.

CQR8ECTIVE STEPS TAKEN AND RESULTS ACHIEVED Upon identification of the concern that cleanliness control requirements were not being adequately implemented, PG&E took prompt action by erecting a barrier to prevent the inadvertent introduction of foreign material into the reactor vessel.

Subsequent management evalution of the barrier determined that modification was necessary to provide assurance against the inadvertent introduction of foreign material into the reactor vessel.

2126S/0060K.

l The supervisory personnel and craftsmen involved in this event were counseled on the need to maintain cleanliness control requirements.

CQRRECTIVE STEPS THAT HILL BE TAKEN TO AVOID FURTHER VIOLATIONS Other instances of inadequate implemention of cleanliness control requirements i

have occurred during the current Unit i refueling outage. As a result of these events, PG&E is undertaking the following actions:

a.

A foreign material exclusion (FME) procedure will be developed to ensure that activities that have the potential to introduce foreign l

l material into the reactor coolant system are evaluated and a determination made of the need to construct appropriate barriers to prevent the introduction of foreign materials into the reactor coolant system. Appropriate administrative, maintenance, and radiation protection procedures will be revised as necessary to ensure consistency with the FME procedure.

The above will ensure compliance with the cleanliness control guidance provided in ANSI N45.2.1.

b.

The role of first line supervision and work planners in implementing cleanliness control requirements will be clarified and strengthened as necessary.

c.

Quality Control will more closely monitor the performance of activities that have the potential to introduce foreign material into the reactor coolant system and additional Quality Control hold points will be used to verify implementation of cleanliness requirements.

DATE HHEN F_ULL COMPLIANCE HILL BE ACHIEVED The above additional corrective actions will be completed prior to the start of the next Unit 2 refueling outage, which is scheduled to begin in September ~T9ES!

~

i B.

STATEMENT OF VIOLATION Facility Technical Specification 6.8.1 states that:

"Hritten procedures shall be established, implemented and maintained covering... applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978...." Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, Section 3.d specifies procedures for "Startup, Operation, and Shutdown of Safety Related PHR I

Systems," and " instructions for... draining... (the)

Emergency Core Cooling System." In partial implementation of this requirement, Operating Procedure (0P) B-3B:III

" Accumulators - Shutdown and Clearing," step B.4 specifies that the operator is to " vent the selected accumulators through the accumulator nitrogen vent valve...," prior to step B.8 which provides direction to " allow the accumulator (s) to drain to the R.C.D.T."

l 2126S/0060K i

i.

Contrary to the above, on March 11, 1988, draining of safety injection accumulators 1-2 and 1-4 was initiated i

prior to venting the accumulators, causing relief valve actuation on the RCDT and release of RCDT inventory to the reactor cavity sump.

This is a Severity Level IV violation (Supplement I) applicable to Unit 1.

i REASON FOR THE VIOLATION IF ADHITTED PG&E acknowledges that the violation occurred as described in the Inspection Report. Operations personnel were concerned about the safety of personnel working in containment and initiated draining of the accumulators to the reactor coolant drain tank without venting the accumulators to containment.

Operations personnel involved in this activity were unaware of the specific procedural requirements for draining the accumulators to the reactor coolant drain tank.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED i

An operations incident summary report was issued to all operations personnel concerning this event.

This report emphasized that it is the responsibility of the shift operating crew'to ensure that procedures which exist for special plant evolutions are used for those evolutions in all cases.

CORRECTIVE STEPS THAT HILL BE TAKEN TO AVOID FURTHER VIOLATIONS This event will be included in the operator requalification training program to reemphasize that shift operating personnel must ensure that the appropri7te procedures are used for performance of operating activities. Administrative-Procedure C-6S1, " Clearance Request-Job Assignment," which provides instructions for equipment clearances, will be revised to clarify the requirements and responsibilities for specifying applicable operating procedures to be used during equipment clearance activities.

DATE HHEN FULL COMPLIANCE HILL BE ACHIEVED Administrative Procedure C-6S1 will be revised by September 1, 1988. This event will be included in the operating requalification program by i

September 2, 1988.

C.

STATEMENT OF VIOLATION 10 CFR 50, Appendix 8, Criteria III, " Design Control" specifies, in part, "Heasures shall be established for the identification and control of design interfaces and for coordination among participating design organizations.

These measures shall include the establishment of procedures among participating design organizations for the review, approval,_ release, distribution, and revision of documents involving design interfaces." In partial r

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implementation of these requirements, Pacific Gas &

Electric Company, Engineering, Nuclear, Procedure No. 3.3, Revision 9 " Design Calculations" specifies in paragraph 4.1.2 that "All design input data... shall be documented in the calculation" and " assumptions requiring verification at a later design stage shall be identified as

' Preliminary' until the verification is completed..."

Paragraph 4.2 " Checking" of Procedure No. 3.3 further specifies that " checking of the calculations shall include

... reviewing calculation inputs to verify conformance with project conditions."

Contrary to the above, on March 11, 1988, Calculation No.

880311-0 had been signed as prepared verified, but was not identified as preliminary even though design input data i

requiring verification was used and had not been verified.

The calculation's result was in error due to dimensional input data being in error.

The input data was in error due to having been informally transmitted by telephone from the site to the design offices. Verification by the NRC on March 21, 1988, found the outside diameter of the thermocouple tube to be 2.625 inches vice the calculations input number of 2.09 inches.

This is a Severity Level IV (Supplement I) violation applicable to Unit 1.

REASON FOR THE VIOLATION IF ADMITTED PG&E acknowledges that the violation occurred as described in the Inspection Report.

The dimension of the thermocouple tube obtained was not the correct dimension to apply at the location of interest, i.e., an error was made in obtaining the thermocouple tube dimension from the drawing.

The dimension was not verified during the calculation process.

j It should be noted that the thermocouple port column venting area was not used exclusively to provide the venting area required for limiting RCS pressure to prevent steam generator nozzle dam failure in the unlikely event of a loss of decay heat removal at the mid-loop condition.

Either the venting area around the unbolted vessel head or lifting the head itself would provide pressure relief before nozzle dam failure occurred.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED The thermocouple tube dimension was reviewed and verified and the calculation was reperformed.

The conclusions of the calculation were unchanged.

The circumstances of this event have been disseminated to NOS personnel who perform safety-related calculations, and the corrective actions discussed below will be implemented pending formal procedure revisions.

2126S/0060K '

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CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS PG&E procedures NOS-3.2.6, " Analysis Verification," NOS-3.2.2, " Documentation j

of Analysis Activities," and NPAP C-20, " Independent Verification of Calculations Important to Safety," have been reviewed and will be revised as necessary to ensure the following.

a.

Source data for parameters critical to the correctness of the calculation will be verified as having been obtained from an approved design document, or when an approved design document is not available, a letter of confirmation will be obtained from the equipment vendor verifying the calculational input value and the applicability to DCPP.

If the above information is not available, measurements from the as-built configuration will be taken and veri fi ed.

b.

Until the source data input is verified by one of the above methods, the calculation will be labeled as " preliminary" and ured for information only.

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED These procedures will be revised by July 29, 1988.

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r' f July 18, 1988 W E CORRESPONDENCE PGLE Letter No. DCL-88-184 U.S. Nuclear Regulatory Commission ATTH:

Document Control Desk Hashington, D.C..

20555 Re: Docket No. 50-275, OL-DPR-80 Diablo Canyon Unit 1 Reply to a Notice of Violation in NRC Inspection Report No. 50-275/88-11 Gentlemen:

NRC Inspection Report No. 50-275/88-11, dated June 17, 1988, contained a Notice of Violation applicable to Diablo Canyon Power Plant (DCPP) Unit 1, citing two Severity Level IV violations regarding (1) cleanliness controls and (2) not following a procedure during maintenance.

PG&E's response to this Notice of Violation is provided in the Enclosure.

The inspection report requested a discussion of a corrective action program to preclude changes to the plant's configuration or parameters without adequate review of plant system design bases.

PG&E provided an overview of the DCPP Configuration Management Task Force activities at the April 26, 1988, PG&E/NRC-Region V management meeting.

PG&E management is presently reviewing the findings and recommendations of the Task Force to evaluate the need for development of action plans.

This review and the determination of the need to formulate an action plan is scheduled for completion by August 15, 1988, and will be discussed with Region V management shortly thereafter.

The inspection report further identified an unresolved item concerning operability of the auxiliary saltwater system (ASHS) during the period when the heat exchanger differential pressure setpoint had been raised.

In response to an earlier request from Region V, PG&E provided a discussion on June 7, 1988, of the design basis for the ASHS and the basis for system qualification.

In response to the ASHS open item discussed in this inspection report, HPG.DCENSIt40 LOG NUMEmp

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s Document Control Desk July 18, 1988-PG&E Letter No. DCL-88-184 1

i PG&E is currently preparing a comprehensive discussion, which is scheduled for submittal by mid-August.

Kindly acknowledge receipt of this material on the enclosed copy of this letter and return it in the enclosed addressed envelope.

Sincerely, s

W' J. D. Shi sr cc:

J. B. Martin H. H. Mendonca P. P. Narbut B. Norton H. Rood NFG DCEN5NG B. H. Vogler LOG NiiMPro CPUC Diablo Distribution 091 Enclosure 22025/0061K/TWL/J063-2 cat P

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PG&E Letter No. DCL-88-184 ENCLOSURE REPLY TO A NOTICE OF VIOLATION IN NRC INSPECTION REPORT N0. 50-275/88-11 On June 17, 1988, as part of NRC Inspection Report No. 50-275/88-11 (Inspection Report), NRC Region V issued a Notice of Violation applicable to l

Diablo Canyon Power Plant (DCPP) Unit 1, citing two. Severity Level IV violations. The statements of violation and PG&E's responses are as follows:

A.

STATEMENT OF VIOLATION 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action" provides, in part, that licensees shall establish measures "to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.

In the case of significant conditions adverse to quality, the measures j

shall assure that the cause of the condition is determined 1

and corrective action taken to preclude repetition...."

Contrary to the above, subsequent to the identification of nonconformances leading to a violation (issued in inspection report 50-275/88-07) for lack of required cleanliness controls on March 21 and April 6,1988, j

corrective actions taken did not preclude repetition.

Specifically, additional incidents of loss of cleaniiness controls were identified un April 9, 12, 21, 22, and May 10, 1988, by NRC and licensee personnel, including the discovery on April 22, 1988 of foreign material on the Unit 1 reactor vessel upper internals.

This is a Severity Level IV Violation (Supplement 1) applicable to Unit 1.

REASON FOR THE VIOLATION IF ADMITTED PG&E acknowledges that the immediate corrective actions taken for the cleanliness control incidents during reactor vessel conoseal removal (on March 21, 1988) and control rod drive mechanism (CRDM) weld repair (on April 6 to 9,1988) were not adequate to preclude other incidents during the Unit 1 refueling outage.

The immediate corrective actions taken for these incidents were to re-establish cleanliness controls.

For example, as discussed in PG&E letter to the NRC of June 6, 1988 (DCL-88-150), PG&E erected a barrier to prevent the inadvertent introduction of foreign material into the reactor vessel during CRDM weld repair activities.

Following an evaluation of the repetitive nature of cleanliness control incidents, it was determined that these incidents occurred because (1) procedures did not provide complete guidance for foreign material exclusion, (2) work planning was inadequate for certain jobs requiring foreign material exclusion, and (3) cleanliness control requirements and responsibilities were not always effectively communicated.

22025/0061K _,

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CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED As described in PGLE letter DCL-88-150, dated June 6,1988, PG&E has evaluated the previous incidents on a generic basis to determine appropriate corrective actions to prevent recurrence.

These corrective actions are described below.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS Administrative Procedure (AP) C-10S4, " Foreign Material Exclusion Area Controls," is being developed to provide guidance on work controls in foreign material exclusion (FME) areas. This FME procedure will ensure that work activities that have the potential to introduce foreign material into the reactor coolant system are evaluated, and a determination made of the need to construct appropriate barriers.

To ensure consistency with the FME procedure, appropriate administrative, maintenance and radiation protection procedures will be revised.

These procedures will include requirements that will ensure compliance with the cleanliness controls guidance provided in ANSI N45.2.1.

To ensure that OC will more closely monitor the performance of activities that have the potential to introduce foreign material into the reactor coolant system, AP C-800S1, "DCPP Quality Control Department Activities," will be revised to require surveillance of housekeeping in containment while the reactor vessel is open.

Procedure QCP 10.2, " Inspection Activities," will be revised to provide guidance for establishing hold points to verify implementation of cleanliness requirements prior to breaching of the eactor coolant system.

Appropriate personnel, including work planners and first-line supervisors, will be trained on the above cleanliness control procedures.

DATE WHEN FULL COMPLI ANCE WILL BE ACHIEVED The above additional corrective actions will be completed prior to the start of the next Unit 2 refueling outage, which is scheduled to begin in September 1988.

B.

STATEMENT OF VIOLATIOR Facility Technical Specification 6.8.1 states that:

" Written procedures shall be established, implemented and maintained covering... applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978...." Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, Section 9, " Procedures for Performing Maintenance," states that " Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances."

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Maintenance Procedure MP M-54.4, " Spiral Hound Gasket Replacement Guide," Revision 7, dated February 16, 1988, provides guidance on the proper replacement of spiral wound gaskets to ensure leak free assemblies. MP M-54.4 includes data sheets required to be completed by the mechanics.

In addition, the procedure in paragraph 7.2.2.d.1 requires the use of Felpro N-5000 lubricant on all mating surfaces of nuts and bolts.

Contrary to the above, on April 27, 1988, while replacing spiral wound gaskets, on a Unit 1 safety injection relief valve header flange, mechanics used an unauthorized lubricant instead of the prescribed Felpro N-5000 and did not complete the data sheets prescribed by MP M-54.4.

This is a Severity Level IV violation (Supplement I) applicable to Unit 1.

REASON FOR THE VIOLATION IF ADHITTED PGLE acknowledges that the violation occurred as described in the Inspection Report. However, PG&E believes that this violation resulted from personnel not being familiar with the maintenance procedure due to inadequate training and tailboarding, not from an inadequate work package.

The work package was originally issued to cover both flange insertion and orifice reinstallation.

Following discovery of installation problems, the work package was reissued to cover only the cleaning and correct reinstallation of the orifice. Only the steps necessary for this activity were included in the reissued package.

The work package inadvertently did not contain all pages of the maintenance procedure.

Also, where written plant procedures exist, work orders normally do not include detailed instructions.

Occasionally, specific steps from procedures may be incorporated into work orders, but in general it is considered undesirable to include large portions of procedures in work orders since these work orders still would not be as complete as procedures nor receive the same level of review.

Also, such reiterations would tend to result in reliance on work orders in lieu of procedures.

The applicable procedures were referenced at the top of the work order in the

" Comments - Special process / equipment / safety" section.

Had the tailboard been adequate, these procedures and the need to follow them would have been reviewed, and problems related to missing pages or following of procedures would have been obviated.

CORRECTIVE STEPS TAKEN AND RESULTS ACHIEVED The flange was removed and the bolts were cleaned and relubricated.

The event was discussed in a Mechanical Planners Meeting. 'The Maintenance Manager issued a Mechanical Maintenance Bulletin to all maintenance personnel reemphasizing the need to follow procedures and work orders, to use proper lubricants, to complete all data sheets, and to resolve questions regarding procedures or work orders with supervision.

2202S/0061K L

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Upon identification of the work order containing only partial procedure pages, Work Planning Center personnel reviewed all active work orders and ensured that all procedures included in them were complete and up-to-date.

The Maintenance Manager held a meeting with foremen, general foremen and other appropriate personnel to review the event.

Emphasis was placed on reviewing procedures in work packages for completeness, following plant procedures, using correct lubricants and filling out data sheets per those procedures, and the need for proper tailboarding. Also, the Maintenance Manager requested the Training Department to add Procedure M-54.4, " Spiral Hound Gasket Replacement Guide," to the schedule for required training prior to the upcoming Unit 2 refueling outage.

In addition, the Quality Control Manager instructed the QC department to not release work orders containing overly general instructions.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS A tailboard checklist / guideline for foremen will be developed which will identify those subjects to be emphasized during tailboards.

Mechanical maintenance foremen will be trained per this guideline, and it will be added to the regular training schedule.

This event will be reviewed at the next Quarterly Mechanical Maintenance Training Seminar. AP B-750, " Maintenance Personnel Training (Qualification of Plant Maintenance Personnel)," will be revised to include more specific requirements for qualification of contractor personnel.

DATE WHEN FULLCOMPLI ANCE WILL BE ACHIEVED The above additional corrective actions will be completed prior to the start of next Unit 2 refueling outage, which is scheduled to begin in September 1988.

2202S/0061K L

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Document Control Desk Washington, D.C.

20555 Re:

Docket No. 50-323, OL-DPR-82 Diablo Canyon Unit 2 Licensee Event Report 2-91-009-01 10 CFR 100 Dose Limits Potentially Exceeded in the Event of a Design Basis Loss of Coolant Accident Recovery as a Result of Valve Leakage Gentlemen:

Pursuant to 10 CFR 50.73(a)(2)(ii)(B), PG&E is submitting the enclosed revision to Licensee Event Report (LER) 2-91-009-00.

This revision is being submitted to report the results of PG&E's investigation into the root cause of this event and the determination of applicable corrective actions.

Sincerely,

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Gregory H. Rueger e

cc:

Ann P. Hodgdon John B. Martin Philip J. Morrill l ACTS LIBRARY Harry Rood CPUC lo Distribution g

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On September 26, 1991, with Unit 2 defueled, leakage of approximately 1.3 gallons per minute (gpm) was identified from diaphragm valves CVCS-2-8471 and CVCS-2-548 in the charging pump suction line during the performance of a hydrostatic test.

The diaphragms in both valves were replaced and the valves tested tatisfactory.

On October 4, 1991, at 1645 PDT, an evaluation of the leakage discovered September 26, 1991, determined that the control room and exclusion area boundary 10 CFR 100 dose limits could be potentially exceeded during the design basis recirculation phase of loss of coolant accident (LOCA) recovery.

On October 4, 1991, at 1800 PDT, a four-hour, non-emergency report was made to the NRC in accordance with 10 CFR 50.72(b)(2)(i).

d The root cause of body-to-bonnet leakage in valve CVCS-2-8471 was personnel error in that the valve was not included in the plant preventive maintenance program.

The root cause of body-to-bonnet leakage from valve CVCS-2-548 could not be determined.

The preventive maintenance program will be revised to include diaphragm replacement frequency and bolt torquing for diaphragm valves.

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Plant Conditions Unit 2 was defueled at the time of the event as part of the Unit 2 fourth l

refueling outage.

II.

Descriotion of Event A.

Event:

Summary u0n October 4,1991, at 1645 PDT, with Unit 2 defueled, an evaluation determined that leakage from valves CVCS-2-548 and CVCS-2-8471 could have resulted in the control room (NA) and exclusion area boundary 10 CFR 100 dosa limits being exceeded during tha recirculation phase of recovery from a design basis loss of coolant accident (LOCA).

CVCS-2-548 and CVCS-2-8471 are located in the chemical and volume control system (CVCS) (CB).

Discussion On September 26, 1991, a hydrostatic test was performed during a scheduled refueling outage, following installation of a new valve in the CVCS.

The hydrostatic test pressurized the charging pump (BQ)(P) suction line portion of the CVCS, During the performance of the hydrostatic test, diaphragm valves CVCS-2-548 (CB)(V) and CVCS-2-6471 (CB)(V) were identified to be leaking. The identified leakage was coming from between the valve body and bonnet on both valves. Leakage from both valves was estimated to be approximately 1.3 gallons per minute (gpm) total.

CVCS-2-548 and CVCS-2-8471 are located in the boric acid blender (CB)

(MIX) room on the 100 foot elevation of the auxiliary building (NF).

Both valves are pressurized during post-LOCA recirculation.

The boric acid blender room ventilation exhausts to the plant vent without passing through charcoal filters (VF)(FLT). Therefore, any radioactive material that may be released as a result of leakage from these valves would be released to the plant vent filtered only by HEPA filters.

On October 4,1991, at 1645 PDT, evaluation of the hydrostatic test data was performed to confirm the leak rates and post-LOCA recirculation pressure. The evaluation determined that leakage from CVCS-2-548 and CVCS-2-8471 could have resulted in the control room and exclusion area boundary 10 CFR 100 dose limits being excceded during the recirculation phase of recovery from a design basis LOCA.

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01ABLO CANYOH UNIT 2 0l5l0l0l0l3l2l3 91 0l0l9 0l1 3 l"l 6 Est 90 On October 4,1991, at 1800 PDT, a four-hour, non-emergency report was made to the NRC in accordance with 10 CFR 50.72(b)(2)(1).

Similar tests were performed during previous Units I and 2 refueling outages, but no similar problems were identified.

B.

Inoperable Structures, Components, or Systems that Contributed to the Event:

Leakage through CVCS-2-548 and CVCS-2-8471 caused the event.

C.

Dates and Approximate Times for Major occurrences.

1.

September 26, 1991:

Event date - CVCS-2-8471 and CVCS-2-548 were observ u to be leaking during the performance of a hydrostatic test.

2.

October 4, 1991, 1645 PDT:

Discovery date - The results of an evaluation indicated that the leak

' rom CVCS-2-548 and CVCS-2-8471 could cause the control room and exclusion area boundary 10 CFR 100 dose limits to potentially be exceeded during the recirculation phase of LOCA recovery.

3.

October 4, 1991, 1800 PDT:

A four-hour, non-emergency report was made to the NRC in accordance with 10 CFR 50.72th)(2)(1).

O.

Other Systems or Secondary functions Affected:

None.

E.

Method of Discovery:

Test engineers observed leakage while performing a hydrostatic test.

F.

Operators Actions:

None.

G.

Safety System Responses:

None.

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III.

Cause of the Event A.

Innediate Cause:

The ir. mediate cause of the plant being outside of its design basis was body-to-bonnet leakage from CVC5-2-548 and CVCS-2-8471.

B.

Root Cause:

1.

The root cause of body-to-bonnet leakage in CVCS-2-8471 was personnel error in that the valve was not included in the plant preventive maintenance (PM) program. Since the valve was not included in the PM program, the diaphragm's service life was exceeded.

2.

Although the specific root cause of body-to-bonnet leakage from CVCS-2-548, which was included in the PM program, could not be determined, the failure to include vendor recommendations on retorquing bonnet bolts in the PM program may have been a factor in the root cause.

IV.

Analysis of the Event A leak of 1.3 gpm in the auxiliary building filtered only by HEPA filters could potentially have resulted in control room operator thyroid dose exceeding the 10 CFR 50 Appendix A General Design Criteria 19 limit over the 30-day duration of the design basis LOCA.

However, post-LOCA emergency response procedures provide for use of self-contained breathing apparatus (SCBAs) and potassium iodide prophylaxis, which would mitigate control room opert'.or thyroid dose.

Control room radiation conditions would be monitored by area radiation monitors located in the control room. Although the monitors are design Class II, they are powered from Class IE power supplies. The area radiation monitors would provide sufficient indication to allow control room operators to don SCBA equipment or take additional i

corrective measures.

l A leak of 1.3 gpm from the auxiliary building filtered only by the HEPA filters could potentially have resiJlted in exceeding the 10 CFR 100 2-hour site boundary dose limit to the thyroid.

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A design basis LOCA dose analysis contains many conservative assumptions, particularly with regards to source ters (i.e. fuel damage), therefore an analysis was peformed by PG&E using

" expected case' LOCA assumptions (no fuel damage).

The analysis determined that a 1.3 gpm leak would result in a 2-hour site boundary thyroid dose of approximately 0.5 rem, which is well below the 10 CFR 100 limit. Therefore, public health and safety were not affected by this event.

V.

Corrective Actions A.

Immediate Corrective Actions:

The diaphrages for CVC5-2-548 and CVCS-2-8471 were replaced.ad the valves were successfully tested to assure that body-to-bonnet leakage did not occur.

B.

Corrective Actions to Prevent Recurrence:

1.

Maintenance Procedure M-51.7, "Grinell Diaphragm Valve Maintenance," will be revised to include vendor recommendations on diaphragm replacement frequency and bolt torquing for diaphragm valves.

2.

A review of installed diaphragm valves was made to ensure that all applicable valves are included in the diaphragm replacement PH program.

VI.

Additional Information A.

Failed Components:

None.

B.

Previous LERs on Similar Events:

LER 1-90-010-00 Control Room Post-LOCA Habitability Design Basis Potentially Exceeded Due to Leakage Through a i

Vibration Induced Crack in CVCS Piping This LER addressed the leakage of post-LOCA coolant into the charging pump rooms. The leakage would have resulted in exceeding the control room design basis dose limit. The cause of the event was determined to be a high cycle fatigue crack in the suction line of the nonsafety-related charging pump.

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The corrective actions for the event included repairing the crack, adding additional supports to the suction line, and revising emergency procedures to assure that the auxiliary building ventilation system (VF) is in the safeguards mode of operation, and consequently, exhaust from the charging pur.p rooms is filtered, after a LOCA.

These corrective actions would not have prevented the leakage from CVCS-2-548 and CVCS-2-8471. The requirement for assuring that the auxiliary building ventilation system is in the safeguards mode would not have prevented the control room or exclusion area boundary dose limit from being exceeded in the event of a LOCA because the boric acid blender room is not part of the safeguards ventilation flowpath.

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n;x mc-me tLa p:w Gerw CORRESPONDENCE 93 OCT 28 P6 :57 June 17, 1991 PG1E Letter No. DCL-91-154

', c U.S. Nuclear Regulatory Commission ATTN:

Document Control Desk Washington, D.C.

20555 Re:

nocket No. 50-275, OL-DPR-80 Diablo Canyon Unit 1 Licensee Event Report 1-91-009-00 Reactor Trip Due to Personnel Error and Safety Injection Due to Leaking Steam Dump Valves Gentlemen:

Pursuant to 10 CFR 50.73(a)(2)(iv) and 10 CFR 50.73(a)(2)(i)(B), PG&E is submitting the enclosed Licensee Event Report (LER) concerning 'a reactor trip resulting from personnel inadvertently satisfying reactor trip logic while performing surveillance testing.

During the recovery from the reactor trip, the reactor coolant system was cooled at a rate greater than 100 degrees fahrenheit in any hour, in violation of Technical Specifications.

This event has in no way affected the health and safety of the public.

Sincerely,

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l. D. Shif cc:

Ann P. Hodgdon John B. Martin Phillip J. Morrill Paul P. Narbut Harry Rood CPUC Diablo Distribution INPO ACTS DCl-91-TI-N047 g224h Enclosure 53915/0085K/ALN/2246 n

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On May 17, 1991, at 0624 PDT, with Unit 1 operating at 100 percent power, a reactor trip occurred due to nuclear instrumentation power range two-out-of-four channels high flux at high setpoint signals.

At 0625 PDT, a safety injection occurred due to two-out-of-four low pressurizer pressure signals.

During the event, reactor coolant system cooldown exceeded the allowable rate of 100 degrees Fahrenheit per hour of Technical Specification 3.4.9.1.b.

An Unusual Event was declared at 0625 PDT on May 17, 1991. A one-hour emergency report required by 10 CFR 50.72(a)(1)(i) was made on May 17, 1991, at 0633 PDT.

The cause of the reactor trip was determined to be personnel error.

An !&C technician inadvertently deenergized a second nuclear instrumentation power range channel (N42) while performing surveillance testing on another power range channel (N41).

The cause of the safety injection was steam dump valves that failed open and overcooled the reactor coolant system.

j i

Corrective actions for the event included: (1) temporary stoppage of all I&C work until 1&C personnel were tailboarded on the necessity of self-verification; and (2) installation of switch and fuse covers on each channel to act as a physical barrier to prevent inadvertent action >.

Corrective actions for the steam dump valves will be discussed in Licensee Event Report 1-90-017-01.

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Plant Conditions Unit I was in Mode 1 (Power Operation) at 100 percent power.

II.

Description of Event A.

Event:

i On May 17,1991, at 0620 PDT, two Instrumentation and Controls (I&C) technicians were performing Survei' lance Test Procedure (STP) I-20,

" Nuclear Power Range Incore/Excore Calibration," on nuclear instrumentation (NI)(IG) power range channel N41. The instrument channel under test had the cabinet instrument drawer (IG)(PL) open.

The next step in the procedure required removal of the fuse (IG)(FU) for reconnection of that channel's signal and high voltage cables.

The technician who was to remove the fuse had previously manipulated the fuse in that channel while the drawer was closed. The technician went to the instrument drawers and inadvertently pulled the fuse for NI channel N42, which had its drawer closed and was adjacent to channel N41.

This resulted in the protection logic recognizing a two-out-of-four high flux at high power signal coincidence for a reactor (AB)(RCT) trip.

On May 17, 1991, at 0624 PDT, with Unit 1 at 100 percent power, a reactor trip occurred due to the protection system two-out-of-four high flux at high setpoint signal coincidence, which initiated a main turbine (TA)(TRB) trip.

Following the reactor and main turbine trips, the condenser steam dump valves (SDV)(SB)(V) automatically opened to prevent reactor coolant system (RCS)(AB) pressure and temperature increase.

RCS pressore and temperature decreased and, to close the SOVs and mitigate the cooldown, a close signal was manually initiated.

Two SDVs,1-PCV-1 and 1-PCV-ll, did not close following the close signal.

Control room operators entered Emergency Procedure E-0, " Reactor Trip or Safety Injection," and verified the automatic responses of the protection system.

l One minute and 38 seconds after the reactor trip, RCS pressure and temperature had decreased sufficiently to result in a safety injection (SI) on two-out-of-four low pressurizer (AB)(PZR) pressure (s3850 psig) signal coincidence.

i An Unusual Event (UE) was declared on May 17, 1991, at 0625 PDT, in response to the SI. Due to previous experience with SDVs failing to close following actuation, operators quickly identified the 5

malfunction.

At 0627 PDT, on May 17, 1991, operators terminated the l

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cooldown by closing the main steam isolation valves (MSIV)(SB)(V) and MSIV bypass valves (SB)(V).

A one-hour emergency report required by 10 CFR 50.72(a)(1)(1) was made on May 17, 1991, at 0633 PDT. This report indicated that RCS pressure 1

dropped from the normal operating pressure (NOP) of 2235 psig to 1640 psig and T,yg dropped from the normal operating temperature (NOT) of i

574 degrees to 507 degrees. Subsequent analysis of recorded data determined that RCS pressure and temperature had reached as low as l

1730 psig and 465 degrees T,y exceeding Technical Specification 3.4.9.1.b. limits for RCS coob,ing of 100 degrees in one hour.

On May 17, 1991, at 0800 PDT, operators returned Unit I to NOP and NOT, and ste,;11 zed the Unit in Mode 3 (Hot Standby).

t B.

Inoperable Structures, Components, or Systems that Contributed to the Event:

None.

C.

Dates and Approximate Times for Major Occurrences:

1.

May 17, 1991, at 0624 PDT:

Event / discovery date. Unit 1 l

reactor trips when a second power range Ni channel is inadvertently i

4 deenergized by an I&C technician, which satisfies the two-out-of-four protection system logic for a i

reactor trip.

2.

May 17, 1991, at 0625 PDT:

An SI results due to RCS pressure decreasing caused by two SDvs leaking excessively following automatic open actuation and manual close signal. A UE is declared.

3.

Hay 17, 1991, at 0627 PDT:

Operators manually close the MSIV and MSIV bypass valves to isolate the SDVs.

4.

May 17, 1991, at 0633 PDT:

A one-hour emergency report required by 10 CFR 50.72(a)(1)(1) was made.

5.

May 17, 1991, at 0800 PDT:

Unit I was stabilized in Mode 3 at N0P and NOT.

53915/0085K

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Other Systems or Secondary functions Affected:

Other than the two SDVs, all equipment functioned as intended to stabilize Unit 1 in Mode 3.

Valves 1-PCV-1 and 1-PCV-11 opened per design but, following closure signal, failed to close.

It was determined that the inner plug stem of the valves separated from the main stem, and resulted in excessive leakage through the valves. The valve stem separation was the result of microwelding of the valve seat. Corrective actions being taken regarding the SDVs failure to close will be dircussed in LER l-90-017-01.

E.

Method of Discovery:

The reactor trip was immediately apparent to plant operators due to alarms and indications received in the control room.

The cause of the SI (SDV failure) was apparent to the operators due to a recent similar transient.

F.

Operators Actions:

Operators verified the automatic functions of the protection system.

Operators closed the SDVs, but the cooldown continued. Operators then closed the MSIV and MSIV bypass valves terminating the cooldown of the RCS.

G.

Safety System Responses:

1.

The reactor tr'p breakers (AA)(BKR) opened.

2.

The control rod drive mechanism (AA)(DRIV) allowed the control rods to drop into the reactor.

3.

The main turbine tripped.

4.

An SI signal was initiated on low pressurizer pressure.

5.

The SI pumps (BQ)(P) started.

6.

The residual heat removal pumps (BP)(P) started.

4 7.

The charging pumps (BQ)(P) started.

8.

The motor-driven auxiliary feedwater (AFW) pumps (BA)(MO)(P) started per design.

9.

Diesel Generators (EK)(DG) 1-1, 1-2, and 1-3 started, and per design did not load.

j391S/00B5K

4 LICENSEE EVENT REPORT (LER) TEXT CONTINUATION T

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DIABLO CANYON UNIT 1 0l5l0l0l0l2l7l5 91 0l0l9 0 l0 5l"l7 fraf (.7)

III.

[3use of the Event A.

Immediate Cause:

An I&C technician, while performing surveillance testing on NI power range channel N41, inadvertently removed a fuse in NI power range channel N42.

B.

Root Cause:

The root cause was determined to be personnel error (cognitive) in that the I&C technician did not perform self-verification.

I&C policy, " Policy For Unit / Channel / Component Self-verification," dated June 30, 1988, requires that an individual verify his own action as correct pr.or to performing the action.

IV.

Analysis of the Event A.

Safety Analysis:

1.

Reactor Trip and Safety Injection:

Impact to the departure from nucleate boiling ratio (DNBR) resulting from accidental depressurization of the RCS caused by secondary side depressurization is analyzed in Section 15.2.13 of the Final Safety Analysis Report (FSAR) Update. Accidental depressurization of the RCS is identified as a Condition II event (Faults of Moderate Frequency). The overcooling and resulting depressurization of the RCS reported in this LER is bounci; by the FSAR Update analysis, and therefore the minimum DNBR was not lower than 1.30 during this event.

2.

Overcooling:

A Westinghouse engineering evaluation of the RCS considered the impact of the thermal transient upon the pressurizer, reactor vessel, RCS piping, the thick metal of the steam generators (AB)(SG), and the reactor coolant pumps (AB)(P).

Westinghouse reviewed temperature and pressure data and compared these with evaluations of similar transients at other plants and the evaluation performed for PG&E's December 24, 1990 rapid cooldown event (LER l-90-017-00).

The comparison showed that the DCPP Unit I rapid cooldown event is bounded by transients previously analyzed. The Westinghouse evaluation concluded that the above described DCPP Unit I transient did not adversely affect the structural integrity of the affected components and system, and that the RCS could be returned to NOP and NOT and the unit restarted safely.

5391S/0085K

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V.

Corrective Actions A.

Immediate Corrective Actions:

1.

The plant was stabilized in Mode 3.

2.

An immediate, temporary I&C work stoppage was directed by management.

I&C personnel were tailboarded on the necessity of sel f-veri fication.

B.

Corrective Actions to Prevent Recurrence:

1.

A temporary physical barrier has been installed over the NI drawer face to prevent inadvertent operation of switches or fuse activity.

1 2.

A memorandum has been sent to Shift Control Technicians informing them of the new temporary physical barriers and their use.

3.

A design change will be implemented to install a permanent, removable physical barrier design for the NI drawers.

4.

In addition to the self-verification training already part of the Maintenance Department training, additional self-verification training will be integrated into I&C laboratory performance training.

5.

The technician involved in the event has been ccunselled as to the necessity ivr.lf-verification.

6.

An INPO video on self-verification practices will be presented to I&C personnel during the quarterly update meeting.

VI.

Additional Information A.

Failed Components:

Copes Vulcan valves 1-PCV-1 and 1-PCV-11, model D-100-160-3, eight inch.

B.

Previous Similar LERs:

1.

ESF Actuations Due To Personnel Error:

LER l-91-005-00, " Actuation of Wrong Test Switch Causes Unplanned Diesel Generator Start (ESF) Actuation due to Personnel Error,"

describes an event wherein a non-licensed operator inadvertently actuated the wrong Sc !d State Protection System (SSPS)(JG) test E3915/0085K

i LICENSEE EVENT REPORT (LER) TEXT CONTINUATION f

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DIABLO CANYON UNIT 1 0l5l0l0l0l2l7l5 91 0l0l9 0l0 7l"l7 staf (37) switch resulting in an unplanned Emergency Diesel Generator start, an ESF actuation.

The root cause of this event was failure to follow self-verification policies. The corrective action did not prevent the most recent event reported in LER l-91-009-00 since the counselling was directed only at Operations personnel.

2.

Condenser 40 Percent Steam Dump '.'a;ves:

LER l-90-017-00, dated January 23, 1991, reported a Unit I reactor trip and SI due to a stuck open pressurizer spray valve.

During this event, SDV l-PCV-1 leaked excessively following actuation. The corrective actions to prevent recurrence for this event dealt primarily with the stuck open pressurizer spray valve which would not have prevented the contributory cause on the S' vs failure reported in LER 1-91-009-00.

The corrective actions to prevent SDV failure have identified but had not been completed on Unit I at the time of the May 17, 1991 reactor trip.

These corrective actions will be described in LER 1-90-017-01, 5391S/0085K

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UNITED STATES

-N NUCLEAR REGULATORY COMMISSION U RECEIVED n

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'*ipqH WASHINGTON, D.C. 2055s NUCLEAR REGULATORY uf o7 ADM ITTd 9 f

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October 27, 1992 NOV 0 31992 M \\G MG

[CHRON l RMS ON D j HD DISTRIBUTION Docket Nos. 50-275 and 50-323 Mr. Gregory M. Rueger Senior Vice President and General Manager Nuclear Power Generation, B14A Pacific Gas and Electric Company 77 Beale Street, Room 1451 J

P.O. Box 770000 San Francisco, California 94177

SUBJECT:

REVIEW 0F RESPONSE TO NRC BULLETIN 92-01, SUPPLEMENT NO. 1 - FAILURE OF THERMO-LAG 330 FIRE BARRIER SYSTEM TO PERFORM ITS SPECIFIED FIRE ENDURANCE FUNCTION - DIABLO CANYON NUCLEAR POWER PLANT, UNIT NOS. 1 AND 2 Supplement I to NRC Bulletin 92-01, " Failure of Thermo-Lag 330 Fire Barrier System to Perform its Specified Fire Endurance Function," requested licensees to:

(1) identify areas of the plant that use either 1 or 3-hour pre-formed Thermo-Lag 330 panels and conduit shapes for the protection and separation of i

the safe shutdown capability; (2) in those plant areas in which Thermo-Lag fire barriers are used in raceways, walls, ceilings, equipment enclosures, or other areas to protect cable trays, conduits, or separate redundant safe shutdown functions, implement, in accordance with plant procedures, the appropriate compensatory measures consistent with those which would be implemented by either the plant Technical Specifications or the operating license for an inoperable fire barrier; and (3) provide a written notification stating whether the licensee has or has not taken the above actions and where the licensee has declared fire barriers inoperable, and describe the measures being taken to ensure or restore fire barrier operability.

We have reviewed your letter dated September 28, 1992, submitted in response to NRC Bulletin 92-01, Supplement 1.

By utilizing a self-contained, portable fire detection system in conjunction with an hourly fire patrol and administrative controls, we conclude that the intent of your technical specifications is still met. We find your selected method of providing fire protection / prevention without reducing the effectiveness of your existing fire protection capability to be acceptable.

Staff acceptance of this methodology RECEIVED NOV 0 61992 CHRISTOPHER J. WARNER

13S601 Mr. Gregory M. Rueger -

is limited to the Diablo Canyon Nuclear Power Plant because of the plant specific nature of the analyses and operating conditions.

If at some future time you change the approved methodology, please inform us.

Sincerely, Harry Roo, Senior Project Manager Project Directorate V Division of Reactor Projects III/IV/V Office of Nuclear Reactor Regulation cc:

See next page i

I

)

o 198601 Mr. Gregory M. Rueger Pacific Gas and Electric Company Diablo Canyon cc:

NRC Resident Inspector Mr. Hank Kocol Diablo Canyon Nuclear Power Plant Radiologic Health Branch c/o U.S. Nuclear Regulatory Commission State Department of Health Services P. O. Box 369 Post Office Box 942732 Avila Beach, California 93424 Sacramento, California 94234 Dr. Richard Ferguson, Energy Chair Sierra Club California Regional Administrator, Region V 6715 Rocky Canyon U.S. Nuclear Regulatory Commission Creston, California 93432 1450 Maria Lane, Suite 210 Walnut Creek, California 94596 Ms. Sandra A. Silver Mothers for Peace Mr. Peter H. Kaufman 660 Granite Creek Road Deputy Attorney General Santa Cruz, California 95065 State of California 110 West A Street, Suite 700 i

Ms. Jacquelyn C. Wheeler San Diego, California 92101 3303 Barranca Court San Luis Obispo, California 93401 Ms. Nancy Culver 192 Luneta Street Managing Editor San Luis Obispo, California 93401 The County Telegram Tribune 1321 Johnson Avenue Michael M. Strumwasser, Esq.

P. O. Box 112 Special Assistant Attorney General San Luis Obispo, California 93406 State of California Department of Justice Chairman 3580 Wilshire Boulevard, Room 800 San Luis Obispo County Board of Los Angeles, California 90010 l

Supervisors I

Room 370

)

County Government Center San Luis Obispo, California 93408 Christopher J. Warner, Esq.

Pacific Gas & Electric Company Post Office Box 7442 San Francisco, California 94120 Diablo Canyon Independent Safety Committee ATTN: Robert T. Wellington, Esq.

Legal Counsel 1

857 Cass Street, Suite D Monterey, California 93940

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4 GCT28 W BErORE THE ATOMIC SAFETY _AND LICENSING BOAP O cqsMX'c" coc cTiN3 8 9

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s' 6 In the Matter of:

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Docket Nos. 50-275-0 03) 7

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50-323-OLA

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8 Pacific Gas and Electric Company

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(Construction Period 20 (Diablo Canyon Nuclear Power

)

Recovery) j 11 Plant, Units 1 and 2)

)

12

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3 13 TESTIMONY OF PACIFIC GAS AND ELECTRIC COMPANY 14 ADDRESSING CO!!TENTION V:

THERMO-LAG COMPENSATORY MEASURES 15 Introduction

)

16 Q1 Please state your name, affiliation, qualifications and 17 current job responsibilities.

)

18 A1 (Cosgrove) My name is David K.

Cosgrove.

I am the 19 Supervisor of the Safety and Fire Protection group a; Diablo 20 Canyon Power Plant ("DCPP").

This group is one of the l

)

21 organizations that comprise the Safety, Health and Emergency

&t OMed tu^5 22 Services ("SHLES") Section within the-Techn W r* E p;cr-t 23 Services Department at DCPP.

The other groups that work

)

24 within this department include the Emergency Planning group 25 and the Fitness for Duty group.

26 As Fire and Safety Supervisor, I am responsible for:

27 the plant Safety Program, 2B the activities of the Industrial Hygienist, 29 the Medical Facility and the Medical Testing 30 Specialists,

O the Fire Marshal and the staff of Industrial Fire 1

e 2

Officers, and the Fire Protection Engineer and the Fire Protection 3

O 4

Specialists.

]

5 I have more than 20 years of experience in the nuclear 6

industry and have been working at DCPP for almost ten years.

7 A summary of my qualifications and experience is provided in l

8 Exhibit 1.

9 (Powers) My name is Robert P. Powers.

I am the Manager O

10 of the Nuclear Quality Services Department within the 11 Nuclear Power Generation ("NPG") Business Unit.

This i

12 Departrent reports directly to the Senior Vice President and j

O 13 General Manager of NPG and is comprised of four sections 14 that independently review DCPP performance.

Until May 1, 15 1993, I was the Manager of the Support Services Department O

16 of DCPP.

The Support Services Department was comprised of l

17 the Safety, Health and Emergency Services section, the NPG i

18 Training Section, the Security Section and the General

'O i

19 Services section.

As the support Services Department f

j 20 Manager, I was responsible for management and direction of L

j 21 all program activities within Support Services, including

O 1

22 those pertaining to fire protection.

{

23 I have more than sixteen years of experience in the l

24 nuclear industry and have been working at DCPP for over

o l

25 eleven years.

A summary of my qualifications and experience j

26 is provided in Exhibit 2.

I io j

27 Q2 What contention will you address:

4

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D 1 A2 We will address San Luis Obispo Mothers for Peace 2

("MFP") Conte,

r, V as admitted in this proceeding, which 4

3 alleges that PG&E is not adequately implementing and D

4 adhering to the interim compensatory measures required by 5

the NRC in connection with the use of Thermo-Lag at the 6

Diablo Canyon Power Plant.

J 7 Q3 What is the purpose of your testimony?

J 8 A3 The purpose of our testimony is to provide a response 9

to the above contention.

We have adequately implemented the 10 Thermo-Lag interim compensatory measures required by the NRC 11 in Bulletin 92-01 and its Supplement 1 in all plant areas in 12 which Thermo-Lag is used as a 1-hour or 3-hour fire barrier.

13 Our implementation of these measures has adhered to all NRC 14 requirements for such measures in Thermo-Lag areas, and the 15 NRC has noted no deviations or violations from requirements.

16 There is no basis for the contention that our implementation

)

17 of these measures has been inadequate.

18 Background

19 Q4 Describe generally the approach taken to fire 20 protection in the program implemented at DCPP.

)

21 A4 The fire protection program at DCPP utilizes a 22

" defense-in-depth" approach that includes a three-part 23 philosophy:

)

24 Prevention:

Prevent fires from starting;

~3-

)

)

1 Detection / Suppression:

Detect fires quickly, suppress 2

those that occur, put them out quickly and limit their 3

range; and D

4 Mitigation:

Design plant safety systems so that, 5

should a fire start, essential plant safety functions 6

will not be prevented from being performed.

D 7

Thermo-Lag fire barriers, in certain applications here 8

at issue, are part of the mitigation echelon of fire J

9 protection.

Specifically, these barriers are designed to 10 limit the range of postulated fires by providing barriers 11 rated for either one or three hours.

The rating of the

)-

12 barrier depends upon the requirements for the specific 13 application.

Firewatches also serve as part of the 14 detection / suppression component of defense-in-depth.

3

)

15 QS How have Thermo-Lag concerns affected DCPP's 16 defense-in-depth program for fire protection?

)

17 AS Testing of Thermo-Lag material has raised questions as 18 to its ability to satisfactorily perform as a fire barrier

)

19 for the rated duration in certain applications.

While 20 Thermo-Lag barriers can be expected to perform their 21 intended function for some length of time, they are

)

22 nevertheless being treated by PG&E as inoperable in those 1

23 very limited locations at DCPP where Thermo-Lag is used to 24 meet cable separation criteria.

Accordingly, interin

)

25 compensatory measures, accepted by the NRC throughout the

_4_

)

1 nuclear industry, are in place at DCPP.

These measures 2

principally include firewatches similar to firewatches used 3

as compensatory measures as allowed by Technical 4

Specifications and the DCPP fire protection program when 5

fire barrier penetrations or other fire protection systems 6

are inoperable.

)

7 Q6 How is the firewatch program utilized in the fire 8

protection program at DCPP generally?

)

I 9 A6 PG&E's Equipment Control Guidelines

(" ECGS") govern the 10 fire detection instrumentation system, the spray and/or

)

11 sr: inkler systems, the CO system, the Halon system, and the 2

12 fire barrier penetrations.

All these ECGS provide for the 8

13 use of firewatch personnel as a compensatory measure when

)

14 any of the systems is not operational.

In some cases, these 15 firewatches are stationed continuously at a specific 16 location.

In other situations, a roving firewatch is used

)

17 to inspect an area or location once each hour.

The use of 18 roving verses continuous usually depends upon whether fire 19 detection devices are available in the area.

The use of

)

20 these types of firewatches to compensate for degraded or

>1 inoperable fire protection systems is an accepted industry I

l 22 practice that is routinely implemented at other nuclear b

23 stations and is a~ epted by the NRC.

l l

) )

I

)

1 DCPP Firewatch Procram 2 07 How is the firewatch program organized at DCPP?

i 3

3 A7 There are two principal types of firewatches used at 4

DCPP:

5 Craft firewatches:

Whenever welding or open flame work 3

6 is performed, a second person must be in the immediate 7

area to act as a firewatch.

These are usually short 8

duration tasks.

These individuals receive specific

.)

9 firewatch training and this task is often fulfilled by 10 the working craftsmen.

These craft firewatches are not 11 typically used to implement compensatory measures when

)

12 fire protection systems are inoperable.

As a result, 13 these "hotwork" firewatches are not affiliated with 14 this contention.

i

)

15 Roving and continuous firewatches:

These personnel are 16 employed exclusively to perform firewatch tasks as 17 compensatory mec.sures (either roving or continuous) 3 18 when a fire protection system is inoperable.

Examples 19 include nonfunctional fire detectors or impaired fire 20 barrier penetrations.

)

21 Infrequently, other plant employees (such as 22 radiographers) may fulfill the role of firewatch during the 23 conduct of special tests or examinations (such as

)

24 radiography) that preclude access to plant areas.

25 In keeping with the DCPP overall fire protection 26 defense-in-depth philosophy, a roving firewatch program has

)

27 been in place essentially since Units 1 and 2 have been in )

I D,

1 operation.

This roving firewatch program was not mandated--

2 by regulation, but was implemented solely at PG&E's 3

discretion.

At a minimum, every hour a roving watch 3

i 4

transits through a majority of the fire areas where safe 5

shutdown equipment is located.

This watch is conducted 24 6

hours a day, 365 days a year, even when all the fire systems D

7 are fully functional.

8 QB How are roving and continuous firewatches supervised D

9 and managed?

j l

10 A8 The roving and continuous firewatch personnel are D

11 contracted through Bechtel Construction Corporation and the 12 DCPP Fire Protection Specialist is responsible for the 13 day-to-day administration of this contract.

The Fire D

14 Protection Specialist is also responsible for maintaining 15 the list of protection systems impairments and for the j

i 16 performance of the routine inspections of the plant fire D

17 barriers.

18 Firewatch foremen are on shift 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day to i

19 supervise the individual firewatch personnel.

The foremen D-20 are available to provide additional technical guidance and 21 to coordinate the establishment of compensatory measures 22 with Operations personnel.

J 23 In addition to the core firewatch personnel routinely i

24 employed at DCPP, an ancillary group of trained firewatch 25 personnel (or "watchstanders") is available in the local

)

26 area and can be called in if areas or locations are i i l

l

D 1

identified that require the use of additional watchstanders.

2 These ancillary firewatches are also available to fill in 3

for the core watchstanders during vacations and illnesses.

J 4 Q9 What training does a firevatch receive?

D 5 A9 Firewatches receive in excess of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of training 6

specifically for the job functions they perform.

They 7

initially attend the same general employee fire protection D

8 training that is provided to all DCPP personnel.

They also 9

complete specific firewatch training, including training on 10 identification of fire protection deficiencies, such as D

11 combustibles and impaired fire barriers, and " hands-on" 12 training on use of portable fire extinguishers.

Attendance 13 at these classes is documented in the Plant Information 3

14 Management System ("PIMS").

15 Firewatches also receive instruction on the 16 identification and control of transient combustibles (i.e.,

3 17 those combustibic materials not permanently installed in the i

18 plant such as wood, paint, solvents, oils and compressed 19 gassesi.

Before assignment to perform firewatch patrols, 3

20 each new watchstander receives several shifts of "on-the-21 job" training with the firewatch foreman, 22 The firewatch foremen receive additional training in 3

23 fire fighting equipment and techniques as well as a 5-week 24 DCPP systems class that includes training in the Final

)

25 Safety Analysis Report Update ("FSAR") and all fire 3

26 protection systems.

Firewatch foremen also receive

_g.

J l

O 1

instruction in fire barrier inspections and perform the 2

monthly fire barrier inspection surveillance when not 3

engaged in actual roving or continuous firewatches.

O 4 Q10 What are the duties and responsibilities of the 5

firewatches?

D 6 A10 Firewatches are required to be knowledgeable of the 7

specific hazards involved in their assignment and to be 3

8 aware of the consequences or potential consequences of any 9

fire in the area.

Firewatch personnel (roving and craft) 10 have no other duties while performing firewatch duties.

)

11 DCPP procedures NPAP A-13,

" Plant Organization for Fire Loss 12 Prevention," and NPAP B-13, " Qualification and Training 13 Requirements of Plant Personnel Specifically Concerned with 3

14 Fire Loss Prevention," describe the responsibilities of the 15 roving and continuous firewatches.

These responsibilities 16 include:

3 17 e

Notifying the shift foreman of all fires and sounding 18 the fire alarm if necessary, 19 Extinguishing fires when obviously within the i

20 capability of the equipment available and his/her 21 training.

22 Satisfying requirements for continuous and hourly

)

23 roving firewatches when fire protection systems / fire 24 barriers are impaired.

25 Satisfying compensatory requirements when combustible

)

26 loading exceeds connitment levels.

_9

)

3:

Maintaining knowledge of the " ignition source area" 1

2 (i.e., safety-related equipment location, special heat 3

sensitive equipment in the area).

4 Q11 Describe how the roving firewatch is typically 5

implemented.

6 All DCPP is comprised of many unique fire areas (or 7

compartments), divided by fire-rated walls, floors and fire B

barriers.

An hourly roving firewatch usually begins his or 9

her round at the top of the hour.

The watchstander walks a 10 standard route through each fire area within Unit 1, Unit 2,

)

11 and the common fire areas each hour.

The fire areas in 12 which interim compensatory measures for Thermo-Lag are in 13 place are included on these routes.

Each tour takes about

)

14 45 minutes.

At the end of each tour, the watchstander 15 usually trades places with another watchstander, and then 16 that watchstander begins the next round at the top of the

)

17 hour1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />.

The length of the tour route and the hourly frequency 18 make it impractical for one individual to perform all the 19 hourly rounds in each 12-hour shift.

(When a continuous 20 watch has been established in an area of the plant as a l

21 compensatory measure, the roving watchstander trades places 22 with the continuous watchstander every hour.)

When

)

23 necessary, the standard tour route is modified or augmented l

24 to include other fire areas or locations if a degraded or 25 impaired fire protection system or barrier has been

)

26 identified.

1Esi\\blON H E.E

]

)

1 Q12 How are these firewatch activities docunented?

2 A12 The roving watch carries a portable electronic "bar

)

3 code" reader wand (similar to those in use et retail 4

markets) which scans bar codes installed in the fire areas 5

along the tour route.

At the end of the shift, the hand

)

6 wand (about the size of a personal calculator) is down-7 loaded to a personal computer and a printout of the watch 8

activities is generated that documents the watchstander's

)

9 name, badge number, the location of each area and the time 10 the watch was in the area.

The program also utilizes a 11 results code, so that any special conditions identified

)

12 during the hourly inspection can also be documented.

The 13 log of the watch activities is maintained on a computer disk 14 and in hardcopy form for one year by the Fire Protection 1

)

15 Specialist.

16 The continuous firewatch records are maintained by hand i

17 and consist of a logsheet that describes the location of the

)

18 continuous watch and a place to record the watchstander's j

1 19 name and the time once each hour.

I

)

20 Q13 What ceasures have been established in the event that a 21 firevatch cannot complete his or her patrol during the hour?

)

22 A13 If a problem occurs during the performance of an hourly 23 firewatch round that causes a delay, the firewatch has been 24 instructed to call or page the firewatch foreman, the

)

25 Industrial Fire Officer or ultimately the Operations Shift,

):

1 Supervisor, if necessary, to arrange for assistance in 2

completion of the hodrly patrol.

During the performance of 3

non-destructive radiographic examinations, when exclusion

)

4 perimeters are established for personnel radiation safety 5

considerations, the radiography examiners are utilized to 6

perform the firewatch activities in the specific plant

)

7 areas.

This requirement occurs infrequently.

8 Q14 What do the firewatches look for?

3' 9 A14 In addition to the obvious conditions that are 10 addressed in general fire protection training, such as J

11 smoke, fire and open fire doors, the firewatches are also 12 briefed each shift on the location of all newly identified 13 impaired or degraded fire systems or barriers.

They carry a 3

14 copy of the list of fire system impairments with them on 15 their rounds, as well as a copy of the relevant fire 16 protection administrative procedures.

They monitor fire

)

17 areas for excessive combustible materials to ensure that 18 permissible quantities are not exceeded.

19 The firewatches also document minor discrepant 20 conditions that they may observe during their rounds, such 21 as burned-out light bulbs and door closers that need to be 22 adjusted.

These discrepancies are reviewed and evaluated by

)

23 the firewatch foreman and the plant fire protection 24 specialist to ensure that adequate corrective actions are 25 implemented.

) )

O 1

Thermo-Lac Firewatches 2 Q15 Did PG&E establish interim compensatory measures in 3

response to NRC Bulletin 92-01 and Supplement 17

O 4 A15 Yes.

On June 29, 1992, DCPP verified that interim 5

O compensatory measures were in place in the plant areas where 6

Thermo-Lag was credited as a fire barrier for conduits and 7

cable trays, consistent with the scope and guidance in NRC 8

Bulletin 92-01.

The Bulletin requested all nuclear plants

'O i

9 to implement interin conpensatory reasures similar to those i

10 that would be required for impaired barriers associated with 4

11 safe shutdown equipment or circuits.

O

]

12 The list of fire areas subject to interin compensatory 13 neasures and PG&E's interim compensatory neasures were 14 subsequently revised in response to Bulletin 92-01,

-O 15 Supplenent 1.

PG&E identified 11 fire areas at DCPP using 16 Thermo-Lag fire barrier systens to separate equipment or 17 circuits associated with safe shutdown of the plant and 0

18 subject to corpensatory meas-res.

The specific location of 19 these installations was described in PGLE's re me to 20 Supplement 1 to NRC Bulletin 92-01 (DCL-92-208, September O

21 28, 1992), which is included as Exhibit 3.

These 22 compensatory reasures were accepted by the NRC (NRC Letter 23 dated October 27, 1992, H.

Rood to G.

M.

Rueger, " Review of 3

24 Response to NRC Bulletin 92-01, Supplement 1").

25 Q16 What modifications, if any, were made to the firevatch 4

26 program to comply with the NRC Bulletin 92-01, Supplement I? O

t 1 A16 DCPP does not make extensive use of Thermo-Lag fire 2

barriers.

The firewatches were briefed cn the specific 3

locations where Thermo-Lag is installed and the tour route

)

4 was slightly modified to encompass the additional fire 5

areas.

These areas are inspected once every hour where fire 6

detection systems are installed, using the existing roving

)

7 firewatch program described earlier.

In those areas of the 8

plant where a detection system is not installed, a Portable 9

Detection System has been installed in conjunction with the 3

10 hourly roving firewatch patrol, in lieu of posting a 11 continuous firewatch.

This Portable Detection System 12 utilizes smoke detectors and a dedicated plant phone system

)

13 to immediately alert plant personnel in the event of a fire 14 in the area and has been approved for use at DCPP by the i

15 NRC.

The Thermo-Lag installations in the Containment

)

16 Buildings are radiant energy heat shields and are not 1-hour 17 or 3-hour fire barriers subject to firewatch compensatory 18 measures.

i 19 Q17 Since the firewatch program was modified in June 1992, e

20 how many missed or late firewatches have occurred in areas

)

21 where Thermo-Lag compensatory measures are in place?

22 A17

-64nce -t he-esta bMe hme nt-crf-thes e compensaroYy Tneas rds i

)

23 in June 199 hourly patrol of the Thermo-La barriers

)

24 has been successfully er{

but one occasion by 25 the assigned firewatch perso e s son this one occasion, on

)

26 February 25, 1993, /duri g a 6-hour perio3Na portion of the s [>EE M l/lSEB ArJ 5to E.R 2

)

1 tota our route was not completed and one Thermo-La ire 2

area (area 3CC, the Unit 2 containment penetrati area on 3

85' eleva on and the 100' elevation) was no accessible to D

4 the firewate This partially completed tour occurred when (R ray) examinations were ing performed on 5

radiographic

\\

/

6 plant welds and a' 1 plant personncI except those involved

?

l 7

with the radiograph were exclVded from this area of the

/

8 plant for personnel r iat)fn safety reasons.

In the 9

unlikely event of a fi during these periods, the personnel 3

10 performing the radi,c raphy would have identified and 11 reported any po ial fire.

l 12 The ov9 all completion su ess rate of the hourly

)

./

13 firewaten in Therno-Lag fire area has been greater than

/

14 99.9 ercent since the init;i.ation-of h d EGYlm pansator-y--resasuresh 15 16 17 Q18 Have the interim compensatory measures been

(,

18 successfully implemented in all other respects?

)

l l

19 A18 Yes.

The firewatch program at DCPP is more proactive j

20 than that at many nuclear stations in that a full-time

)

21 hourly roving watch is maintained at all times, regardless l

l 22 of the status of the individual fire protection systems.

23 When the NRC issued Bulletin 92-01, DCPP was not required to

)

24 develop a new program to provide the required interim 25 compensatory measures.

Instead, an established program, 26 with training and procedures, was adopted and employed

)

27 successfully to address Thermo-Lag areas.

The DCPP b

O 1

firewatches are dedicated, competent personnel who 2

understand the significance of the job they perform.

On the 3

backshifts and weekends, these firewatches are literally the

'O 4

eyes and ears (and nose) of the plant.

At no time since the 5

operation of the plant has there ever been a fire in an area 6

where safe shutdown equipment is located that impacted the 0

7 operation of the plant or the capability to safely shut down 3

8 the plant.

i

!O 9

Ipcidents Cited by MFP 10 Q19 MFP, in the original basis statement for this 4

11 Contention, claim that a number of specific deficiencies lO 12 show that the Thermo-Lag compensatory measures have not been 13 implemented effectively.

Others were listed in discovery.

14 Please respond.

O 15 A19 MFP listed five incidents in their basis statement for i

16 the contention and listed 35 documents in their O

17 June 21, 1993 discovery response (Appendix B).

These are 18 alleged by the MTP to be indicative of inadequacies in the i

19 DCPP firewatch program.

However, only two of these O

20 incidents represent an actual missed firewatch that occurred 21 because the firewatch was either physically restricted from 22 or detained in the performance of the firewatch rounds.

()

23 These two instances occurred prior to June 1992, before the 24 Thermo-Lag compensatory firewatches were established.

25 In one case, on September 17, 1991, the hourly roving O

26 firewatch tour was not fully completed because the roving

] 0 1

D 1

watch was not able to promptly exit from the radiologically 2

controlled area of the plant and exchange duties with the 3

firewatch in the turbine building.

The firewatch was 4

delayed by radiation protection personnel, while they 5

evaluated some indications of radioactive contamination.

6 The contamination was eventually traced to the presence of 7

naturally occurring Radon (a radioactive material) on the 8

firewatches' clothes.

The roving watch tour was not 9

performed for two hours.

This event is documented in LER 10 1-91-015-00, dated October 16, 1991.

11 The second event occurred on June 20, 1992, when the 12 turbine building was evacuated as a prudent personnel safety 13 measure due to an acid and caustic chemical spill.

The 14 roving firewatch was not performed for eight hours in areas 15 of the plant affected by the spill.

This event is addressed 16 in LER 1-92-007-00, dated July 20, 1992.

17 In the overall context of the DCPP fire protection 18 program, these two isolated instances are not significant 19 because the associated fire detection and suppression l

20 systems remained fully functional during these periods.

21 Moreover, since 1985, the roving firewatches at DCPP have

)

22 successfully completed in excess of 99.90 percent of the 23 scheduled rounds.

24 A majority of the remaining items listed by MFP have 3

25 little or no relevance to the adequacy of the firewatch 26 program.

For the most part, these documents address fire 27 protection equipment deficiencies (impairments) such as

)

28 breached fire barriers or inoperable fire detectors. )

1 Breached barriers and inoperabic barriers are not 2

deficiencies in firewatches.

When discovered, these 3

equipment impairments require the establishment of either 3

4 continuous or roving firewatches until they are repaired.

5 When docunented in LERs, these deficiencies by convention 6

are classified as " missed firewatches," not as " breached

)

7 fire barrier" or " inoperable detector," because the 8

compensatory measures were not in place while the component 9

was impaired.

However, the firewatches in fact were not l

10

" missed," but were not yet instituted only because the l

l 11 impairment was not yet identified.

l 12 Furthernore, none of the itens cited are associated D

I 13 with Thermo-Lag fire barrier raterial or firewatches in the l

1 14 11 Therro-Lag areas subject to interim compensatory 1

15 neasures.

Thus, they cannot support a theory that we have 3

l 16 not adequately implemented the specific set of firewatches 1

l 17 that constitute the Therno-Lag interin compensatory 18 measures.

)

19 Q20 Did any of the incidents cited by the MFP significantly

)

20 impact the fire protection capabilities at DCPP?

21 A20 No.

The individual incidents cited generally address 22 specific equipnent malfunctions or individual design 23 discrepancies, and when viewed in the overall DCPP fire 24 protection context represent a minical reduction in the 25 total " defense-in-depth" program. )

D' 1

The fire protection program is multifaceted and 2

includes a central alarming fire detection system that is 3

regularly inspected and tested.

Also, many areas of the D'

4 plant are equipped with automatic fire suppression systems 5

such as water sprinklers, carbon dioxide or Halon gas.

In 6

addition, the design of the plant includes extensive use of D

7 redundant equipment, circuits, and fire barriers other than 8

Thermo-Lag, such that a fire in one area would not impact 9

the ability of the plant to safely shutdown.

Major fire

)

10 areas containing switchgear and power distribution equipment 11 are separated at DCPP by fire area boundaries from other 12 redundant trains, thereby eliminating the need for extensive D

13 use of Thermo-Lag to achieve cable separation requirements.

14 Also, administrative controls limit the amount of temporary 15 combustible materials permitted in the plant.

Finally, all 3

16 DCPP plant employees receive initial and yearly 17 requalification training which includes fire protection 18 safety.

The success of the DCPP fire protection program is

)

19 not dependent solely on the performance of one portion of 20 the program, but rather on the consolidation of many l

21 individual attributes that comprise the " defense-in-depth"

)

22 philosophy.

l l

l 23 Q21 Does this conclude your testimony?

l 24 A21

Yes, I 3

)I I.,IST OF EXHIBITS 1.

Professional qualifications of David K.

Cosgrove 2.

Professional qualifications of Robert P. Powers 3.

PG&E Response to NRC Bulletin 92-01, Supplement 1, DCL-92-208, dated September 28, 1992

)

)

l I

k

)

)

1 l

l

Q11 Describe how the roving firewatch is typically implemented.

All DCPP is comprised of many unique fire areas (or l

compartments), divided by fire-rated walls, floors and fire barriers.

An hourly roving firewatch usually begins his or 1

her round at the top of the hour.

The watchstander walks a standard route through each fire area within Unit 1, Unit 2, and the common fire areas each hour.

The fire areas in which interim compensatory measures for Thermo-Lag are in place are included on these routes.

Each tour takes about 45 minutes.

At the end of each tour, the watchstander usually trades places with another watchstander, and then that watchstander begins the next round at the top of the hour.

The length of the tour route and the hourly frequency make it impractical for one individual to perform all the hourly rounds in each 12-hour shift.

(When a continuous I

watch has been established in an area of the plant as a compensatory measure, the roving watchstander trades places with the continuous watchstander every hour.)

When the standard tour route is modified or augmented necessary, to include other fire areas or locations if a degraded or impaired fire protection system or barrier has been identified.

The intake structure fire area is not included on the roving tour route because of its remote location.

A dedicated firewatch is assigned to that area.

1

Q17 Since the firewatch program was modified in June 1992, how many missed or late firewatches have occurred in areas where Thermo-Lag compensatory measures are in place?

A17 Since the establishment of these compensatory measures in June 1992, hourly patrols of the Thermo-Lag fire areas have been successfully performed by the assigned firewatch

)

personnel.

On several occasions, a portion of the total tour route was not accessible to the firewatch.

These instances occurred, for example, when radiographic (X-ray) examinations were being performed on plant welds and all plant personnel except those involved with the radiography were excluded from this area of the plant for personnel radiation safety reasons.

Nonetheless, we have determined that in all cases the Thermo-Lag fire areas were actually observed within the hour by the firewatch at a separate location, thus satisfying the compensatory measures.

In addition, as discussed above, under the current firewatch program, radiographers can fulfill the function of the I

firewatchers.

The overall completion success rate of the hourly l

J firewatch in Thermo-Lag fire areas has been 100 percent since the initiation of the interim compensatory measures.

f i

4 EXHIBIT 1 PROFESSIONAL QUALIFICATIO!;S O

or DAVID K. COSGROVE O

O i

O O

O O'

O O

O

RESUME SoPerem so r2.

op 3,s g ey y-a,fn 7,rz6 P/asec; rid

- _EANAGER = NUCLEAR-QUAEITY"BERVICES David K.

Cosgrove 1.

Birthdate - October 22, 1951 2.

Citizenship - USA

)

3.

Education & Qualifications a.

Five senesters toward a B.S.

in Mechanical Engineering b.

U.S.

Navy Nuclear Power School (Qualified in Submarines)

PG&E Technical Staff Training Program c.

1 j

4.

Erployment History a.

January 1971 to December 1977 - U.S. Navy Submarine Service b.

September 1980 to February 1984 - Quality Assurance Engineer for Bechtel Power Corporation for engineering & design activities in the San Francisco General Office and later for f

field construction activities at Washington Nuclear Project

1. 2 in Richland, WA.

c.

February 1984 to Novenber 1925 - Quality Assurance Supervisor for Bechtel Power Corporation at Diablo Canyon Power Plant for the On-Site Engineering Group and later for f

Field Construction Activities for the Bechtel Site Services group as the construction completion contractor.

d.

November 1985 to August 1991 - Quality Control Specialist for Pacific Gas and Electric Co. in Nuclear Plant Operations at Diablo Canyon Power Plant with responsibility for the

[

oversight of the Quality Evaluation probler resolution progran and a Quality Control representative at Ncnconformance Technical Review Groups, e.

August 1991 - Supervisor of the Safety and Fire Protection grcup:

h Responsible for the administration of the plant safety program through the Plant Safety group and the Industrial Hygienist.

l Supervision of the Fire Protection program, including l

)

the fire suppression and fire barrier systems through the Fire Protection specialists and system engineer including the plant firewatches, and the Fire / Emergency Response progran through the Plant Fire Marshal, including the Fire Brigade and the Industrial Fire Officers.

Adninistration of the site Medical Facility for routine and energency redical treatrent as well as the Medical Testing specialists that administer required redical exans.

)

4 EXHIBIT 2 PROFESSIOI;AL QUALIFICATIO!!S OT ROBERT P.

POWERS O

O b

b a

P J

D RESUME MANAGER, NUCLEAR QUALITY SERVICES i

Robert P.

Powers D

i 1.

Birthdate - February 20, 1954 j

2.

Citizenship - USA 3.

Education J

a.

B.S.,

Biology, Tufts University, Medford Massachusetts, 1975.

b.

M.S., Radiological Physics, University of North Carolina, Chapel Hill, North Carolina, 1976.

J 4.

Erployrent History - Joined PG&E in July 1982.

a.

December 1976 - July 1982 - Health Physicist - Tennessee Valley Authority.

j b.

July 1982 - Erployed by PG&E - Assigned to General Office, Nuclear Operations Support as a Health Physicist and Senior Nuclear Generation Engineer.

c.

September 1984 - Assigned to Chemistry and Radiation Protection Department at DCPP as a Senior Chemistry and j

Radiation Protection Engineer.

d.

January 1987 - March 1987 - Rotational Assignment to Acting Manager Quality Control.

e.

July 19EE - Promoted to Manager of the Radiation Protection Departrent.

f.

February 1990- Assigned to Senior Reactor Operator License Class.

g.

May 1991 - Certified as Senior Reactor Operator - DCPP.

)

h.

June 1991 - Assigned as Director, Mechanical Maintenance.

i.

July 1992 - Promoted to Manager, Support Services, j.

May 1993 - Promoted to Manager, Nuclear Quality Services.

)

5.

Nuclear Experience a.

Health Physicist in the Tennessee Valley Authority's Nuclear Program with assignments in environmental monitoring, radiation desiretry, operational health physics, emergency planning, and uraniur nining and milling.

b.

Ccrtified as a Health Physicist by the American Board of Health Physics, 19E2

)

~ -.

~~

D c.

Health Physicist and Senior Nuclear Generation Engineer in PG&E's Nuclear Power Program.

Assigned to the General Office with responsibilities in dosimetry, operational plant support, and emergency planning.

D I

d.

Senior Chemistry and Radiation Protection Engineer, DCPP.

Responsible for all aspects of applied health physics program for DCPP Units 1 and 2.

i e.

Acting Manager of DCPP Quality Control Department.

Managed

)

)

all aspects of the plant Quality Control Programs.

f.

Manager, Radiation Protection Department, DCPP.

g.

Received Senior Reactor Operator's Certification, DCPP Units I and 2, 5/9/

[

I i

h.

Director of Mechanical Maintenance - Responsible for all aspects of turbine, pump, valve, HVAC, reactor and steam generator maintenance for DCPP Units 1 and 2.

i.

Manager Support Services - Responsible for Training, 3

Security, Building and Land Services, Emergency Planning, Fire Protection and Industrial Safety.

6.

Formal Training a.

Senior Reactor Operator Class /1990 - 1991/DCPP -

3 participated and completed 15 months of classroom, simulator, and on-the-job assignments leading to certification as a Senior Reactor Operator.

/Y sk b.

InterAal Datimetry Class - 1989 - one week class by Dr. N. Sgfable, University of Lowell, covering detailed

)

analysis of dose calculation of internally dsyposited j

radionuclides.

g

)

c.

Uranium Mining and Milling - 1982 - one week class by Eberline Co. on radiological impact and assessment of mining and milling operations.

J

\\

)

)

)

)

EXHIBIT 3 FO&E RESPO!?SE TO NRC BULLETIli 92-01, SUPPLEMEl;T 1 DCL-92-208, DATED SEPTEMBER 28, 1992 i

l I

D l

P i

l i

P i

I I

l 3

)

J

~

)-

Pacific Cas and Ele:tric Cornpny 77 Eirt S: er G t;: fM Fue;er Sr F r:c CA 9.05 St.9er W.! Frts cen: ans 415 FH59 S m i m e;r

...:r P.,.r Grrr.:n 1

September 25, 1992 I

PGLE Letter fios. DCL-92-208 HEL-92-050 U.S. tiuclear Regulatory Comm.ission ATTri:

Document Control Desk Washington, D.C.

20555 D

m M

Re:

Docket tio. 50-275, OL-DPR-80 Docket tio. 50-323, OL-DPR-E2 Diablo Canycn Units 1 and 2 Docket tio. 50-133, OL-DPR-7 D

Hurboldt Bay Power Plant, Unit 3 Response to Supplement 1 of tiRC Bulletin 92-01 Gentlemen:

PG5f *

• respcnte to Supplerent 1 of tiRC Eulletin 92-01, Failure of 3

Tns Lag 330 fire Barrier System to Perform its Specified Fire Endurance functicr., dated August 28, 1992, is provided in the enclosure.

PGLE is following the efforts coordinated by t4UMARC regarding the industry fire barrier operability assurance and restoraticr. effcris.

The tiUMARC prcgram includes establishment of a database cf iterro-Lag 330 tests, development of guidance for test applicability to as-built configurations, development of more detailed generic inst allatier. guidance, and consideration and coordination of additior.al iherr.o-Lag 330 testing as appropriate.

Results of the tiUtiARC prcgrar will be reviewed for applicability to DCPP when available.

Sincerely, 6

][G 0. Lu.~ b hx}. /$ap.s Gregcry l' Rutger cc:

Eiff Eradiev O

Ann P. H;dg'dtn John B. Martin Philip J. M;rrill Harry Rood CFUC Diablo Distribution HEPP Distributien Enclosure SE465/85K/Alfy2242 D

G

PG&E Letter Nos. DCL-92-208 h

HEL-92-060 ENCLOSURE RESPONSE TO SUPPLEMENT 1 0F NRC BULLETIN 92-01 Supplerent 1 to NRC Eulletin 92-01,

• Failure of Thermo-Lag 330 Fire Barrier System to Perform its Specified Fire Endurance Function,' requested licensees to:

(1) identify areas of the plant that use either 1-or 3-hour pre-formed Thermo-Lag 330 panels and conduit shapes for the protection and separation of the safe shutdc n capability; (2) in those plant areas in which Thermo-Lag g'

fire barriers are used in ra.eways, walls, ceilings, equipment enclosures, or other areas to protect :able trays, conduits, or separate redundant safe shutdos n f unctions, irplement in accordance with plant procedures the appropriate compensatory measures consistent with those which would be implemented by either the plant Technical Specifications or the operating license for an incperable fire barrier; and (3) provide a written notification O

stating whether the licensee has or has not taken the above actions, and where the licensee has ce:lared fire barriers inoperable, describe the measures being taken tc ensure er restore fire barrier operability.

PGLE reviewed the ac;1icability of Supplement I to Bulletin 92-01 for Humboldt 1

Eay Power Plant (HEFP) and determined that HEPP does not use Thermo-Lag fire O

barriers.

PGLE also revie ed Supplement I for Diablo Canyon Power Plant (D:PP).

As a result cf the expansion of scope in Supplement 1, PGLE has added three add"tional fire area (Nos. 9,10, and 11 of Table 1) to the fire areas previously identified in PG5E's original response to Bulletin 92-01. The fire areas in which Therm:-Lag is used as a 1-or 3-hour fire barrier are itemized in Table 1.

D:PP Technical Specification (TS) 3.7.10,

• Fire Barrier Penetrations,"

requicas for non-functional fire barrier penetrations either that an hourly fire watch be established in combination with operable fire detectors or that a continuous fire watch be established.

As a result of the uncertainties e

associated with c;alification of Thermo-Lag fire barrier systems, PGLE has O

taken action consistent with TS 3.7.10 for the Thermo-Lag fire barriers in the fire areas described in Table 1, until such tirc that information is available to verify the ade;uacy cf these Thermo-Lag systems or to verify the level of protection provided by such syste s.

As a conservative reasure to augrent the approved Appendix R Fire Protection O

Program, DCPP has raintained hourly fire watches in effect since the beginning of com ercial operation in all safe shutdown fire areas (except in the Units 1 and 2 containments and intake structure) where DCPP credits Appendix R safe shutdo-n circuits. Also, in general, the combustible loadings for the DCPP fire areas with Thermo-Lag are relatively low.

As interim compensatory measures in response to the original Bulletin and to Supplement 1, PGLE g

expanded the scope of the hourly fire watches to inciude the intake strutture and verified that the fire areas with operable fire detection equipment where D:PP credits the use of Thermo-Lag to protect Appendix R safe shutdown l

circuits have been covered by the hourly roving fire watches.

In addition, FG5E posted continuous fire watches for Fire Areas 22-C and 13-E.

Fire Area 22-C has citrable su;pression (automatic wet pipe) capability, but does not

'g tase crerable fire cetection equip ent.

Fire Area 13-E has neither detection cr su;;ressicn ca; ability.

SE ES/EEK 1 3

3 In PGLE's original response to Bulletin 92-01 (PGLE letter DCL-92-173, dated July 29, 1992), PGLE had conservatively included the two containment Fire Areas 1 and 9, which each have one 1.5 inch o conduit and boxes made from pre-formed Thermo-Lag panels for fire junction boxes. These Thermo-Lag systems in O

the containment buildings are located in the annular areas, which are relatively free of combustibles. The major fire hazards in the containment buildings are the reactor coolant pump (RCP) motor oil and grease, but each RCP is provided with an automatic wet-pipe sprinkler system.

In addition, the containment buildings are provided with both smoke and flame detection systems.

However, PGLE considers these Thermo-Lag installations in the O

containments to be radiant energy heat shields, and not 1-or 3-hour fire barriers.

The basis for considering these installations to be heat shields is presented in Attachrent 1.

As discussed with the NRC, PG&E is of the understanding that Thermo-Lag installations considered to be heat shields rather than barriers do not f all under the requirements of Bulletin 92-01 or Supplement 1, and therefore PG&E has not included Fire Areas 1 and 9 in this O

response to Supplement 1.

Also, in PGLE's original response to Eulletin 92-01, PGLE had included Fire Area 19-A, which has two 2-inch o conduits and boxes made from pre-formed Thermo-Lag panels for two junction boxes.

Fire Area 19-A has operable fire suppression capability and is included in the scope of the hourly fire watches 4

that PGLE has maintained since the beginning of commercial operation.

PG&E has determined that this fire Area need not have been included in the scope of Eulletin 92-01 and Supplement 1.

This determination is based on the consideration that the Thermo-Lag was installed as a prudent measure to protect the circuits for auxiliary saltwater solenoid valves FCV-602 and FCV-603, only one of which needs to be operable to achieve Mode 3 (Hot g

Standby).

In the event of a fire in this area, the circuits for these valves cculd be disabicd by hot shorts.

If both valves are postulated to be made inoperable through the hot shorts, then as described in Emergency Operating Procedure (EP) M-10, the valves may be made operable by venting.

Fire Area 19-A therefore has not been included in the scope of Supplement 1.

k'ith respcct to fire Area 3-l, this Area has partial smoke detection, but PGLE 3

has determined that the detectors are net in close enough proximity to the Thermo-Lag enclosure to credit as a compensatory measure. The Thermo-Lag enclosure is used to protect emergency lighting circuits, and not safe shutdown functions per se, to ensure that lighting is available for operater access to valves EE05A and E2058.

In conjunction with the hourly fire watch, PGLE has installed S-hour battery-operated lights to ensure that a lighted g

access path for operators is available.

In addition, the room in which the Thermo-Lag enclosure is installed is designated as a 'No Storage Area".

k'hile PG&E has stationed continuous fire watches in the two remaining areas where Therro-lag is credited and that do not have fire detection equipment, PGLE proposes to use a portable detection system (PDS) for these areas, in i

O conjunction with an hourly fire watch in place of the continuous fire watch.

An evaluation performed in accordance with the guidance of 10 CFR 50.59 is provided as Attachrent 2 for the use of the PD5.

PGLE proposes to implement I

use of the PDS following concurrence from the NRC.

l b

l SEES /E5K D

Table 1 9

i Thermo-Lag insta!!ations i

I gl Thermo-Lag Compensa:ory Fire Fire Area (FA)

Insta'lation De:e: tion Suppression Actions Duration j

(minutes) i l

l 1. FA 3-BB One 3 c conduit; box Smoke Sprinkjers Hourly Fire 17

{

(Unit I made from pre-formed Watch j

O Containment pane!s for one l~ c Pene: ration conduit; boxes made Area) frem pre-formed panels for 5 junction boxes i2. T/s 3 CC Two 3" c conduits; Smoke SprirJJers Hourly Fire 11 O

(Unit 2 boxes made from pre-wa::h Con:ainrnent formeJ panels for 6 Pene:ra: ion Area) jun:: ion boxes 3.

FA 3-L One 4' c conduit; box Nor.e None Con:inuous Fire 15 (85 Foo: Eleva: ion made from pre-fermed Watch, er Hourly O

Auxiliari rane: f r 1 jun: tion Fire Watch with Eu:: ding) tox Temporary 8-hout Ligh:.s to ensure a lighted prh in case of Thermo-Lag failure causing loss Q

of viutilights f. FA 4 B 4

One C c cendua Smoke SprirJJers Houriv Eire Wa::h 32 (A::ess Con ran

5. FA 5-A4 One :~ c-condui:

Smoke None Hourly Fire Wat:h 34 0

(Unit I #ED V Swi::h; ear Room) i 6. FA 5-B-4 One :" e condua Smoke None Hourly Fire Wa::h 34 (Unit : 480 V Swi::hrear Roemi O

7.

FA ::-C Two :~ c conduis None SprirJJ ets Con:inuous Fire 9

(Unit 2 Diesel Watch, or Portable Genera:or Detection System Cerr; dor) with Hourly Fire l

Wa::h O

g.

ya 30.A-5 Individua) boxes made Smoke High pressure Hourly Fire Watch 19 (Units I and 2 from pre-forrned panels CO: for In:ake Struorure) for two l' e conduits, circulating two 2" c conduits, and water pump four 3* c condui:.s; motors I

b " '

• d' = I

O l

fctmed p2nels for :

jur.:: ion t:aet 554CS!E5:.

O

Table !

)

Thenno-Lag installations (cont'd)

)-

Thermo-Lag Compensatory Fire Fire Area (FA)

Installation Dete: tion Suppression Actions Duration l

(minutes)

9. F A 10 Thermo-Lag / Pyro: rete Smoke None Hourly Fire 23

)

(Unit 1 - 12 kV Barrier Wat:h Switchger Room) l t

20. FA 20 Thermo-Lag / Pyro: rete Smoke None Hourly Fire 23 l

(Unit 2 - 12 kV Barrier Watch l

)

Swit:h;er Room) l.

! 11. FA 13-Elll-B 2 Partia) Wall constru:ted None/Nonc None/None Continuous Fire 2 min' (107 Foot of pre formed Thermo-Wat:h, or Ponable 2 min l

Eleva:icn TurMne Lag panels Dete: tion System t

}

Building) with Hourly Fire Watch m

)

?

i l-l

)

?

SS465/E5K

)

4

)

PGLE considers the Thermo-Lag configurations inside the Units 1 and 2 containments to be radiant energy heat shields.

The basis for this consideration is provided in the following clarification.

JO CFR 50. Appendiy R. Receirements

)

The requirements of Appendix R for " Fire protection of safe shutdown capability" are outlined under Section'Ill.G.2 of Appendix R.

Specifically, Appendix R requires that one of the following fire protection means be provided inside non-inerted containments:

III.G.2.d:

" Separation of cables and equipment and associated nonsafety

)

circuits of redundant trains by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards";

Ill.G.2.e:

' Installation of fire detectors and an automatic fire suppression system in the fire area"; or

)

III.G.2.f:

" Separation of cables and equipment and associated nonsafety circuits of redundant trains by a noncombustible radiant energy shield."

4 PGLE Sub-ittals

)

)

On September 23, 1953, PG1E provided supplemental information to the tiRC regarding FGLE's compliance with Section Ill.G, Ill.J, III.L, and 111.0 of Appendix R.

In item 1 of the Enclosure to that letter, PG&E committed to

• provide either a radiant energy s:.ield or 1-hour rated fire barriers for the reactor coolant temperature instrumentation."

In Section 9.6.1.1 of Supplemental Safety Evaluation Report 23, the fiRC staff concluded that *With the installation of a 1-hour fire-rated barrier or radiant energy shield..." the technical requirements of Section Ill.G.2 of Appendix R in containment would be met and that a deviation from the requirements of Appendix R was no longer necessary.

Due to the fact that 3

there are no provisions for use of a 1-hour fire-rated barrier to comply with Section Ill.G.2 of Appendix R inside containment, it is concluded that the fiRC staff considered the Thermo-Lag barrier as a radiant energy shield.

Generic letter (GU E5-10

)

Turther, Section 3.7.1 of GL ES-10 provides the tiRC's interpretation of

" noncombustible radiant energy shields." As outlined in GL 86-10, radiant energy shields are provided so that

• radiant energy from a fire involving the cables from one division would not degrade or ignite cables of the other divisions. The shields also direct the convective energy from the fire away

)

from the surviving division." The example cited in GL 66-10 for a radiant energy shield is a 1/2-inch marinite board in a metal frame. The 1/2-inch i

thickness gerinite board provides a fire endurance of 1/2 hour, which SE455/E5K 3

)

corresponds to the guidelines outlined in Section C.7.a(1)b of Eranch Technical Position (BTP) CMEB 9.5-1.

Within the response provided in GL 85-10 is a position in which the NRC has previously accepted "nonfire-rated radiant energy shields that have been demonstrated by fire hazards analysis to provide

)

an acceptable level of protection against the anticipated hazard of a localized fire within containment."

Thermo-Lag is classified as a " noncombustible" material based on tests, performed in accordance with ASTM E84 Standards by Underwriters Laboratories, with the following results Flame Spread 5

fuel Contributed 0

1 Smoke Developed 15 Section 5.4.1 of ETF AFCSB 9.5-1 identifies noncombustible materials as those D

whose properties exhibit a flare spread, smoke, and fuel contribution of 25 or less when tested in acccrdance with ASTM EE4 Standards.

Conclusien J

In accordance with the above discussion, PG5E considers the Thermo-Lag installaticns in the Units 1 and 2 containments to be radiant energy heat shields.

As discussed with the hRC, PGLE is of the understanding that Thermo-Lag installaticns considered to be heat shields rather than barriers do not fall under the recuirements of Eulletin 92-01 or Supplement 1; therefore, PG5E has not included Fire Areas 1 and 9 in this response to Supplement 1.

D D

'e O

e EE E5!EEE e

)-

10 CFP. 50.59 Safety Evaluation

)

DESCRIPTION OF CHANGE

~

This safety evaluation evaluates the acceptability of the design of the Portable Detection System (PDS) for use in DCPP Units 1 and 2.

This safety

)

evaluation will evaluate procedures that will control operation of the PDS and evaluate the technical review of the design of the PDS. The following documents will be covered by this safety evaluation:

SJrveillance Test Procedure (STP) 1-30, " Portable Detection System Installation Testing and Operation Procedure"

)

STP 1-34K, " Portable Detection System Weekly Test" Compliance Review with NPPA 72 (1990), "" Standard for the Installation, Maintenance, and Use of Protective Signaling Systems"

)

The PDS is a self-contained, portable fire detecting system that consists of a panel, UL-listed, commercial-grade fire detectors, cables, and end-of-line connectors.

The PDS is powered by 120V AC power and has a 12V DC battery backup. The panel is an enclosed metal case with a hinged lockable door. The panel contains switches for AC and battery power, buzzer, detector zones 1 and 2, and external bell / strobe lights (optional). The panel has indicator LEDs

)

for alarm, trouble, and normal conditions for detector zones 1 and 2.

The panel also hac LEDs for normal and trouble indication for AC power and a telephone line, and for battery power operation and low battery power. The PDS uses a voice-synthesized dialer to communicate / transmit supervisory and alarm signals via messages. The messages specify the location of the panel and the type of signal (trouble or alarm).

)

The PDS will be used, in lieu of a permanently installed fire detection system, as an " operable fire detector" to assist the plant in detecting fires.

~hn limiting condition for cperation for TS 3/4.7.10, " Fire Barrier Fe..etrations," recuires that "all fire barrier penetrations (including cable penetration barriers, fire doors, and fire dampers) in fire area boundaries protecting safety-related areas shall be functional." Whenever the fire i

)

barrier penetration is non-functional or cannot perform its intended design function, TS 3/4.7.10 specifically requires that:

With one or more of the above required fire barrier penetrations non-functional, within 1 bour, either establish a continuous fire watch on at least one side of the affected penetration, or

)

verify the OPERABillTY of fire detectors on at least one side of the non-functional fire barrier and establish an hourly fire watch patrol.

There are two Thermo-Lag configurations (Fire Areas 22-C and 13-E) that do not have a detection system that fulfills the intent of TS 3.7.10, and therefore a

)

continucus fire watch has been established.

In order to provide a means of fire protection / prevention withcut reducing the effectiveness of the existing fire protection capability, FGSE has proposed to use the PDS, in conjunction SS455/E5K )

1 a

0 with an hourly fire patrol and administrative controls, as an acceptable cogensatory reasure for the Thermo-Lag fire barriers.

9 The design of the PDS was reviewed against the requirements of the 1990 edition of NFPA 72.

Because fiFPA 72 is written primarily for fire detection systems that arE permanently installed, it is expected that the PDS will not ccmply fully with the requirements / recommendations provided in tiFPA 72.

The basis for acceptability of " deviations" or " complies with intent" to tiFPA 72 has been evaluated with respect to using the PDS in lieu of a permanently 3

installed fire detection system.

Because a fire patrol will be provided on an hourly basis to check the PDS connections, power supply, operation, and phone line availability, and procedures for functional tests will be implemented, the use of the FDS was determined to be technically compatible with a permanently installed detection system.

Acceptability of the implementing procedures, in conjunction with an hourly fire patrol, will ensure that the PD3 will perform its intended function.

Thus, the effectiveness of the Fire g

Protecticn Prcgram is maintained.

SCREENIN3 CRITEM A FG; DETERP.INING THE HEED FDR A SAFETY EVALUATIDN 1.

Je rr; 56 5; 5:#et e Enluatier Screen a)

Yes h:

)

Does it involve a chance to the Technical Specifications (Appendix A of the DCPP Operating license) or the license itself?

(NOTE:

if the answer to this question is "YES,

skip b-e and proceed to part 2, the Environmental Protection p

Plan screen.)

b)

Yes No i

Does it involve a change to the DCFP facility as described in the FSAR?

c) its

)

h:

Does it involve a change to a procedure 9

(including the Fire Protection Plan or procedures) as described in the FSAR (i.e., Does it change system operation or administrative control over plant activities as described in the F5AR)?

O d)

Yes t:

1 Does it involve a test or experirent that could result in the operation of the facility in a manner not described in the FSAR or which could have an adverse effect on nuclear safety?

e)

Yes hD Y

Does it involve a change to DCPP facilities or e

procedures that could affect nuclear safety in a way not previously evaluated in the FSAR because it was not anticipated?

IE:ES/EEK 9

).

2.

Environmental Protection Plan Screen Yes tio X

Does it involve a change to DCPP procedures or design which could affect the environment, or a

)

change to the Environmental Protection Plan?

(Appendix B of the DCPP Operating License.)

3.

Ereroency Plan Screen Yes No X

Does it involve a change to the DCPP Emergency i

)

Plan (EP) or emergency response equipment or procedures described in the EP?

4.

Security Plan Screen Yes tio X

May it involve a change to the Security Plan or

)

Safeguards Contingency Plan or to equipment or procedures described in the Security Plan or Safeguards Contingency Plan?

The PDS, in conjunction with an hourly fire patrol, may be used in lieu of a permanently installed detection system to fulfill the action statement for 1

TS 3/4.7.10. TS fire barriers are part of the Fire Protection Program. Use J

of the PDS is a change to system operation and administrative control of plant activities.

Administrative controls are provided when using the PDS to ensure use of the 120V AC power supply and dedicated telephone line does not impact other DCPP com,ittents (i.e., Security Plan or Emergency Plan).

b 30 CFR 50.59 SAFETY EVALUATION As c'escribed in the Safety Evaluation Screen, the PDS, in conjunction with an hourly fire patrol and administrative controls, will be used as a compensatory ceasure for Thermo-tag barriers that do not have operable fire detectors.

)

The design of the PDS was compared against the requirements / recommendations of tiFPA 72 (1990), and where the design " deviated" or " complied with the intent" of tiFPA 72, a basis for acceptability was provided. Based on the intended use of the system, in corjunction with an hourly fire patrol and administrative controls, which will verify PDS connections, power supply, operation, and phone line availability, and the completion of functional tests, the use of

)

the PDS was determined to be technically compatible with a permanently installed detection system. A dedicated phone line will be used with the PDS to ensere party lines and connections for existing phones and phone lines are not affected.

Operation of the PDS will require a 120V AC power supply source and an operable telephone line.

In addition, a backu

)

PDS in the event of a loss of a power source. p battery is provided for the Detectors are installed in one or two independent zones (up to 25 detectors per zone) per PDS panel, and when activated (by smoke particles or heat), will transmit a signal to the PDS control panel.

The detectors are connected to the panel via cables. The cable wires are soldered to nine pin connectors that are screwed to female

)

receptacles on the detectors and panel.

This type of connector ensures there will be no inadvertent disconnects to cause false alarms or render the PDS SE45S/E5K r

)

inoperable. The dialer will call eight (8) designated phone numbers to notify the recipient of a fire in the specified location. The phone numbers to be called are: Unit 1 Control Room, Unit 2 Control Room, Fire Watch Supervisor,

)

Shif t Supervisor, Central Alarm Station, Secondary Alarm Station, Industrial Fire Office, and the Safety Manager. The PDS dialer will continue to call each of these stations until an individual answers the phone and takes action to investigate the location of the alarm and reset the panel.

Investigation of the fire alarm in accordance with existing emergency procedures will be conducted, and followup actions will be taken accordingly.

)

Upon installation, the PDS will be tested in accordance with the installation testing and operation procedure (STP I-34J). This procedure also provides instructions for care and maintenance while the PDS is in storage status.

While the PDS is in use, th( PDS will undergo a weekly functional test (STP I-34K) and a 6-month function:1. test (STP I-34L). The performance of these tests ensures that the PDS is functional by testing the alarm and

)

trouble circuits for continuity, manually notifying the designated phone numbers on the dialer, and verifying that the proper messages are being transmitted from the recorder.

In addition, the 6-month functional test ensures the PDS panel cables and detectors are functional (i.e., detectors are checked for sensitivity and activated using test gas).

If at any point the hourly fire patrol or the individual responsible for the test determines that

)

the operability of the PDS is not acceptable, a continuous fire watch is posted within an hour in accordance with TS 3/4.7.10 and the PDS is removed.

Yes fic Y Hay the probability of occurrence of an accident previously evaluated in the FSAR be increased?

)

Justification: The PDS may be used as a means of fire detection in support of TS 3/4.7.10. The PDS will be placed in an area that currently does not have any detection.

The PDS will utilize 120V AC and a telephone line for operation, and will not interact with equipment important to safety or its support equipment. Therefore,

)

the occurrence of design basis accidents previously evaluated in the FSAR Update will not be affected.

Fire detectors will be connected to the PDS via cables, thereby introducing transient combustible materials to the area of concern.

The transient combustible loading introduced by the PDS will be

),

reviewed prior to installation to ensure transient combustible loading limits are not exceeded.

In order to ensure the cables do not dangle and interact with equipment, they will be attached with wire ties in accordance with Administrative Procedure (AP) C-65,

" Temporary Attachments." Each PDS could, at most, monitor 25 fire detectors per zone (the PDS can accommodate 2 zones), and each

)

detector on each zone is connected with cable connections.

Placement of the fire detectors is monitored by a fire protection engineer to ensure compliance with NFPA 72E requirements. The PDS panel is made of fire-resistive material and will not contribute to the combustible loading.

)

in addition, the PDS is not an ignition source ar'd will not create a fire. Therefore, use of the PDS will not be a fire hazard, and the probability of a fire occurring in the area remains the same.

55 ES/SEK )

4 Failure of the PDS will not affect equipment important to safety.

In the event the hourly fire patrol determines the PDS is non-functional or unable to perform its intended function, then the PDS is either replaced with another PDS or a continuous fire watch is 4

posted (as required by TS 3/4.7.10).

The probability of occurrence of any accident previously evaluated in the FSAR Update will remain the same.

Yes No y May the consequences of an accident previously evaluated in O

Justification: As stated above, the PDS will not affect operation of equipment important to safety. Therefore, if an accident previously evaluated in the FSAR Update occurs, equipment expected to mitigate the consequences of the accident will be available. No new accidents will be created by the use of the PDS and an hourly O

fire patrol.

The hourly patrol verifies the PDS has adequate power and the phone line is adequately connected and operable.

In addition, a weekly functional test and a 6-month functional test are performed. The E

fire patrol and functional tests ensure that the PDS will be operational to notify appropriate personnel immediately, in the event a fire occurs within the hour.

If a fire occurs, operators and fire brigade members will mitigate the consequences of the fire in accordance with existing procedures. The consequences of a fire propagating across a TS barrier has not been evaluated in the d

Appendix R analysis (Sectinn 9.5 of the FSAR Update). The Appendix F analysis relies on the functional integrity of the TS fire barrier to confine or re+ ard fires from spreading to redundant safe shutdown equipment to ensure that at least one train of systems necessary to shut down the plant will be free from fire damage.

The use of the PDS will provide early detection of the fire and h

reduce the potential for circuit damage to redundant equipment required for safe shutdown as documented in the Appendix R analysis.

Section 9.5 of the FSAR Update will be reviewed to ensure Fire Protection Program commitments are not violated (i.e.,

verify that intervening combustibles are not introduced between redundant components where separation is credited).

The Telecommunications group will also be notified upon installation of o

the PDS to ensure Communications commitments are not violated.

The PDS, hourly fire patrol, and daily, weekly, and semiannual functional tests ensure that if a fire were to occur, it would be detected and suppressed during its incipient stage and would not prcpagate across the T5 barrier. Therefore, the consequences of a 6

fire as eva uated in the FSAR Update will not be affected.

Yes No. X May the probability of occurrence of a malfunction of equipment important-to-safety, previously evaluated in the FSAR, be increased?

O SEUS/EEK I

D Justification: Use of the PDS will not interact with equipment important to safety. The PDS will require a 120V AC and an operable telephone line.

The power outlets used in the area do not 3

provide power to vital equipment; therefore, plugging in the PDS will not affect operation of safety-related equipment.

In the event 120V AC power is lost, a battery back-up (12V DC source) is provided, and a trouble alarm is initiated locally. When the backup battery's voltage drops to ll.5V, a trouble signal is then initiated remotely (i.e., a " trouble" phone call is made to designated stations).

g In addition, the telephone line is not used for operation of safety equipment; therefore, plugging in the PDS to an existing telep5cne line will not affect equipment important to safety. The PDS will be installed on a dedicated phone line and coordinated with Telecom unications to ensure commitments are not violated. The use O

cf the PDS and administrative controls on phones on the same phone line will not affect the existing Communication Evaluation performed for thc Appendix R analysis (Calculation No. E-134DC).

Therefore, the probability of occurrence of malfunction of equipment irportant to safety, previously evaluated in the FSAR Update, will not be affected.

The PDS will be used to provide early detection of a fire and reduce the potential for fire damage to redundant components and/or circuits.

The effects of a fire on equipment important to safety has been evaluated in the Appendix R analysis.

The actions or equipment used (e.g., telephones) to mitigate fire-induced O

malfunctions of equiprent irportant to sa'ety will be the same as previously evaluated in Section 9.5 of the FSAR Update.

Yes No Y May the consequences of a malfunction of equipment important to safety, prev.cusly evaluated in the FSAR, be increased?

Justification: As stated above, the use of the PDS does not affect the function of equipment important to safety. Therefore, the conse:;uences of malfunction cf equipment important to safety will remain the same.

g The PDS will provide early detection of a fire in the area.

The hourly fire patrol will check en PDS operability by verifying power is supplied to the PDS, the telephone line is connected, and the fire detector zone (s) is connected. Other administrative controls (such as weekly and 6-month functional tests) are implemented to verify operability of the PDS.

This will ensure that the PDS will provide early indication in the event of a fire within the fire g

watch's hourly patrol.

Yes No X May the possibility of an accident of a different type than any already evaluated in the FSAR, be created?

dp Justification: The PDS is not a fire hazard.

Installation of the FCS will te evaluatcd to ensure transient combustible loading SE455/ESK 0

D limits are not exceeded and commitments in Section 9.5 of the FSAR Update (Fire Protection) are not violated.

In addition, installation of the PDS will be coordinated with Telecommunications j

to ensure communications commitments are not affected. The use of 3

an existing telephone line will not affect plant operation. Where necessary, dedicated phone lines will be installed for use by the PDS. This will ensure the phone line is available for use by the PDS.

If the phone line is connected to a phone required by other Diablo commitments (e.g., Security Plan or Emergency Plan), the PDS will not be used on that particular phone line, and a dedicated line will be utilized.

g The PDS and detectors are not seismically qualified. Attention will be given to location of the detectcrs and connection cables to ensure that in the event of an earthquake, the detectors and cables will not affect Seismically Induced Systems Interaction (SISI) targets. The criteria for not affecting SISI targets as described O

in the 5151 Manual will be reviewed by qualified reviewers prior to installation of the PDS panel and its detectors to ensure SISI concerns are not created. The existing fire detection system is not required to be seismically qualified; therefore, the PDS does not have to be seismically qualified.

D Therefore, a new type of accident will not be created by use of the PDS.

Yes No Y May the possibility of a malfunction of equipment important to safety of a different type than any previously evaluated

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in the FSAR, be created?

uu tification: Use of the 120V AC power source and existing telephone line will not impact the operation of equipment important to safety.

Therefore, the possibility ef a malfunction of equipment of a different type will not be created. Where D

necessary, dedicated phone lines are used to ensure that commitments are not violated.

Phones that are required or committed for other reasons (e.g.,

Security Plan or Emergency Plan) will not be used by the PDS.

l Prior to installing the PDS, a representative from l

O Teleco=anications will approve placement of the PDS and ensure i

that commitments are not affected by the installation.

In l

addition, Section 9.5 of the FSAR Update will be reviewed to ensure l

commitments made in the Fire Protection Program are not affected.

l In addition, because the PDS and detectors are not seismically F) qualified, attention will be made to installation of detectors and l

connecting cables to ensure that in the event of an earthquake, the detectors and cables will not affect operation of SISI targets.

The PDS will not be used in areas where SISI targets may be affected.

SISI requirements will be coordinated with a qualified individual.

The criteria in the SISI Hanual will be reviewed to

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er.sure the potential for creating SIS!s due to installation of the PDS will not be involved.

SS455/E5K )

h Yes fic X Does the proposed change, test or experiment reduce the margin of safety as defined in the basis for any Technical Specification?

h Justification: The PDS, in conjunction with the hourly fire patrol and administrative controls, will be used as a compensatory measure for the Thermo-Lag fire barriers. Use of the PDS will maintain the margin of safety as described in the basis of TS 3/4.7.10. The PDS, in conjunction with the hourly fire patrol verifying operation of the PDS (i.e., check the power connection, telephone connection,

'O detector zone connection, etc.) provides an equivalent level of fire protection of a permanently installed fire detection system.

In addition, the PDS is checked weekly to ensure the dialer and battery backup works properly. A functional test is performed upon installation and every six months to ensure proper operation of the PDS.

In the event the PDS is determined non-functional, a c

continuous fire watch is posted in accordance with TS 3/4.7.10.

O fiFPA Code Comparison Review was conducted to evaluate the basis for acceptability of " deviations" and " complies with intent" of the code requirements. Because the system is not a permanent system, it was not expected to fully comply with the code. The temporary

L use of the system, in conjunction with the fire patrol and

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additional administrative controls, provides an equivalent level of fire protection consistent with a permanently installed detection system that woLid have been used, if it was available, in accordance with the action statements of TS 3/4.7.10.

t TS 3/4.3.3.8, " Fire Detection Instrumentation," is not affected by 9

use of the PDS. The PDS is used to supplement the permanently installed detection systems required by TS 3/4.3.3.8.

As stated in the basis of TS 3/4.3.3.8:

The operability of detection instrumentation ensures that adequate warning capability is O

available for prompt detection of fires. This capability is required in order to detect and locate fires in their early stages.

Prompt detection of fires will reduce the potential for damage to safety-related equipment and is an integral element in the overall facility Fire o

Protection Program.

The intent of using the PDS to satisfy the TS 3/4.7.10 action statement for Thermo-Lag fire barriers is to provide early detection of a fire.

The hourly fire patrol and additional administrative controls will provide assurance that the PDS is as O

reliable as a permanently installed system.

Yes tio X May this change result in a decrease of effectiveness of the Fire Protection Plan?

Indicate the Fire Protection Plan (FSAP Update, Section 9.5, Volume I

O

11) sections reviewed?

SE465/85K O

h if the answer to the above question is "no", provide a statement j

justifying the conclusion.

Include the following:

a.

Cite and describe the sections of the Fire Protection Plan b

being changed.

i 4

b.

Describe the proposed change and how it affects the effectiveness of the program.

c.

Cite and describe the applicable NRC requirements (ircluding 3

the NRC basis of acceptance) or PG&E commitments and justify that the proposed revision meets these requirements or commitments.

The Fire Protection Plan credits the functional integrity of fire barriers to ensure that fires will be confined or 3

adequately retarded from spreading to adjacent portions of the facility.

TS 3/4.7.10 provides action statements to provide an equivalent level of fire protection in the event a fire barrier or its penetrations is non-functional. The design of the PDS was reviewed against the requirements of NFPA 72. which is applicable to permanently installed detection systems. Because the PDS is a " portable system" and not a permanent a9 installation, several requirements of the code could not be met. The basis for acceptability of the

• deviations" and

corplies with intent' are documented in the Code Compliance Review.

Because of the temporary use of the PDS, the hourly fire patrol, and additional administrative controls, the use of the PDS is determined to be an equivalent level of fire protection.

The PDS is not de a ribed in Section 9.5 of the FSAR Update.

The FDS supplements the permanently installed fire detection system, and therefore does not reduce the ability to detect fires as described in the FSAR Update. The PDS is a temporary 9

means of fire detection.

Use of the PDS does not reduce the effectiveness of the Fire Protection Program or change the descripticn of the fire detection system in Section E.1 of Table B-1 of Section 9.55.

The use of the PDS was discussed with the NRC prior to 3

irplementation. The NRC appeared to not have a technical concern with using the PDS and an hourly fire patrol, but requested a safety evaluation be performed to determine that an unreviewed safety question is not created.

In addition, Section 9.5 of the FSAR Update will be reviewed to e

ensure that co=ittents made in the fire Protection Program are not affected.

Based on the above safety evaluation, use of the PDS will not reduce the effectiveness of the approved Fire Protection Program.

r6 SS455/85K O

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Conclusion Based upon the above criteria and justification, PG&E has determined that an unreviewed safety question is not involved.

Further, a change to the'DCPP

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Technical Specifications is not involved.

2. - Environmental Protection Plan Evaluation Not applicable.

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3.

Emeraency Plan Evaluation - 10 CFR 50.54(o)

Not applicable.

4.

Security Plant Evaluation - 10 CFR 50.54(o)

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flot applicable.

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3

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t

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ES455/S5K '

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