IR 05000275/1995011
| ML16342C995 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 07/26/1995 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342C994 | List: |
| References | |
| 50-275-95-11, 50-323-95-11, NUDOCS 9508020045 | |
| Download: ML16342C995 (52) | |
Text
ENCLOSURE U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-275/95-11 50-323/95-11 Licenses:
DPR-80 DPR-82 Licensee:
Pacific Gas and Electric Company 77 Beale Street, Room 1451 P.O.
Box 770000 San Francisco, California Facility Name:
Diablo Canyon Nuclear Power Plant, Units 1 and
Inspection At:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
May 14 through June 24, 1995 Approved:
Inspectors:
M. Tschiltz, Senior Resident Inspector G. Johnston, Senior Project Inspector M. Miller, Project Manager, NRR H. J.
Wong, C ie
,
actor roJects Branc ate Ins ection Summar Areas Ins ected Units 1 and
Routine announced inspection of operational safety verification, plant maintenance, surveillance observations, onsite engineering, plant support activities, followup operations, followup engineering, and in-office review of licensee event reports (LERs).
Results Units 1 and
Operations:
Operations performance was effective in the identification of a potentially deficient condition and planning power reductions directed by the system dispatcher.
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During routine surveillance testing of the turbine-driven (TD) Auxiliary Feedwater (AFW)
Pump 1-1, an operator noted several blades were cracked on the outboard bearing fan.
This problem was noted in an area with limited access and lighting, and demonstrated a questioning attitude regarding plant equipment material condition and operability (Section 4.1.2).
9508020045 950727 PDR ADOCK 05000275
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Operations management preplanned a strategy for power reductions requested by the system dispatcher.
These actions were considered to have been proactive and demonstrated an appropriate concern For safety (Section 1.3.1).
Maintenance:
Licensee performance in this area was generally effective with a few weaknesses identified.
Prompt and comprehensive actions were taken by the licensee in the investigation of the failure of a level control valve to operate; however, minor weaknesses were noted in the licensee's performance of some maintenance and testing activities.
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Troubleshooting of Steam Generator (SG) 2-3 AFW level control, motor-operated valve revealed a potential generic problem with a magnetic contactor.
To resolve the problem a
100 percent inspection was performed of all similar magnetic contactors installed in safety-related applications.
The evaluation of this issue was time'ly and demonstrated an awareness of, and sensitivity to, the problem's potential effect on safety (Section 3.2).
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Weaknesses in attention-to-detail for administrative controls established for jumper logs resulted in the failure to perform a
periodic walkdown of a nonsafety-related jumper (Section 2. 1.4).
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A combination of failure to Follow maintenance procedures (MPs), unclear work instructions, and system leakage led to the inadvertent release of carbon dioxide which resulted in the evacuation of all personnel from the intake structure (Section 1.4).
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Contrary to the licensee's MPs, the monitoring of freeze seal temperature and periodic injections of carbon dioxide to the seal jacket were not performed as required during the repair of Valve AFW-2-168.
A noncited violation was issued (Section 3. 1.5).
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The lack of attention-to-detail and inadequate verification during Technical Specification (TS) required testing resulted in testing a
containment penetration in the wrong unit (Section 5.1).
The licensee's overall performance was excellent in this area and was particularly notable in the identification and rapid response to a
vulnerability to a main steam line break (MSLB) which could cause a failure of the solid state protection system (SSPS).
Oversight organizations contributed to improving plant safety.
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A design reconstruction review performed by the licensee's engineering staff found that the SSPS input circuitry could be electrically grounded
during an NSLB.
The existence of inadequate electrical separation between safety-related and nonsafety-related circuits is considered to have been a violation.
A noncited violation was issued (Section 8. 1).
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The nuclear oversight organizations were providing substantial contributions to the improved effectiveness of activities and plant safety at Diablo Canyon.
The Independent Safety Evaluation Group ( ISEG)
is providing insightful analysis of site safety-related activities (Section 5.2).
The licensee's performance was generally good based on the inspectors'outine review of radiation protection, chemistry, and security practices.
However, the licensee was slow to completely resolve deficiencies in emergency lighting.
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The licensee identified in 1990, with notification to the NRC in 1992, that it failed to provide adequate emergency lighting for safe shutdown areas of the plant.
It was four years after identification of the issue (in 1994) that the licensee requested NRC approval for the long term use of flashlights in lieu of permanently installed lights.
This request was rejected by the NRC staff in 1995.
A noncited violation was issued (Section 6. 1)
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Summar of Ins ection Findin s:
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A noncited violation was identified (Section 3. 1.5).
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A noncited violation was identified (Section 6. 1).
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A noncited violation was identified (Section 8.1).
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Unresolved Items 275/9502-01 and 323/9502-01 were closed (Section 8. 1).
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Violation 323/9502-01 was closed (Section 7. 1).
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LERs 275/94-015, Revision 0 and Revision 1; 275/94-017, Revision 0 and Revision 1;
and 323/95-001, Revision 0, were closed (Section 9).
Attachments:
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Attachment 1 - Persons Contacted and Exit Meeting
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Attachment 2 - Acronyms
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DETAILS
PLANT STATUS (71707)
1.1 Unit
Unit 1 began the inspection period at 100 percent power.
Power was reduced on several occasions during periods of lower demand for electrical power at the request of the Pacific Gas 8 Electric Company system dispatcher.
The power reductions were up to 500 Hegawatts for intervals of up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
1.2 Unit 2 Unit 2 began the inspection period at 100 percent power.
The Unit was curtailed to 50 percent power on June 2,
1995, to perform scraping of marine growth from the Circulating Water (CW)
Pump 2-1 conduits and perform cleaning of marine fouling of the condenser.
The scraping and cleaning was completed on June 4,
1995.
Power ascension to 100 percent commenced on June 4,
1995, and was completed on June 5,
1995.
Unit 2 operated at 100 percent for the remainder of the inspection period.
1.3 Plant 0 erations Durin Reactor Power Chan es Background -
On several different occasions Units
and 2 were requested by the Pacific Gas and Electric system dispatcher to reduce power output.
This was due to power generation capacity exceeding power demand due to the availability of hydroelectric and wind power.
During these periods, the Operations Director provided the operators with general operational guidelines'hese guidelines provided limitations on the magnitude of the power reductions and the number of power reductions per week for each unit.
The guidelines took into consideration the effect the transients would have on Unit 2 reactor coolant system iodine activity due to the existing fuel pin defects and addressed the effect of the power level changes on core operating limits.
1.3.1 Conclusion The actions taken by operations management to plan for anticipated reduced power operations allowed operators to review specific requirements applicable during these periods.
The licensee's preparation and preplanning for these operations is considered to have been proactive and demonstrated an appropriate concern for safety.
1.4 Carbon Dioxide Dischar e Durin Fire Su ression S stem Haintenance Background On Hay 31, 1995, maintenance was performed on the carbon dioxide fire extinguishing system located in the intake structure.
This system provides fire suppression protection for th'e CW pump motors'he maintenance
involved replacement of the carbon dioxide control cylinder which actuates the control valves isolating the high pressure carbon dioxide cylinders from the remainder of the system.
During the control cylinder replacement, the supply hoses connect'ing the control cylinder to the control valves were not disconnected as required by the HP.
Following reinstallation of the carbon dioxide control cylinder, pressure was supplied via the supply hoses to the control valves causing them to open.
The volume of carbon dioxide supplied. by the control cylinder was insufficient to open the actuation valves which discharge carbon dioxide into each of the CW pump motor enclosures.
Several leaks in the portion of the system which supplies CW Pump 2-2 motor enclosure resulted in the release of the contents of carbon dioxide cylinders into the intake structure atmosphere.
The personnel performing the maintenance noted the discharge of carbon dioxide and notified operations.
1.4.1 Evacuation of the Intake Structure Upon noting the discharge of carbon dioxide, all personnel, including access control security guards, were evacuated from the intake structure.
Several licensee personnel subsequently reentered the intake structure after donning self-contained breathing apparatus to attempt to isolate the source of the discharge.
Security guards were relocated to a temporary location outside the intake structure and reestablished control of access.
Samples of the intake atmosphere indicated carbon dioxide levels were noted to be below the level at which requires the use of self-contained breathing apparatus, and significantly below the level considered immediately dangerous to life and health.
Isolated areas of higher concentrations of carbon dioxide were suspected to exist in the lower elevations of the intake structure.
Licensee personnel established additional ventilation of the intake structure through the use of portable blowers and temporary ducting to facilitate lowering the carbon dioxide concentration.
Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following the discharge, the licensee reestablished normal access to the intake structure.
The licensee's response to the discharge appeared appropriate.
1.4.2 Maintenance Instructions for Control Cylinder Replacement The maintenance procedure utilized for the control cylinder replacement was MP-18.6, Revision 5,
"Semi-Annual Preventive Maintenance on Permanently Installed CO-2 Cylinders for the CW Pump Motors."
This procedure contained instructions for the semi-annual maintenance performed on the system.
Only a small portion of the procedure was applicable to the replacement of the control cylinder.
The work order, which was written for the work, specified that the control cylinder be replaced in accordance with HP 18.6.
As a result of lack of familiarity with the system in combination with inexplicit work instructions, specific procedural steps were improperly considered by the maintenance personnel to be not applicable.
Specifically, the instructions of Sections 7. 1.4 and 7. 1.5, which disconnected the supply hoses to flow control valve (fCV)-ll'2 and fCV-113, were not performed as intende.4.3 Safety Significance The intake carbon dioxide fire extinguishing system provides fire suppression protection only for the CW pump motors which are not safety-related equipment.
The system is not credited as part of the licensee's
CFR Part 50, Appendix R, fire protection program.
The licensee had the capability at all times to gain access to the safety-related equipment, if needed, by using self-contained breathing apparatus.
The inspectors also noted that there were sufficient qualified personnel available to perform these actions, if required'he licensee subsequently completed corrective maintenance on the intake carbon dioxide fire extinguishing system and returned it to operational status.
1.4.4 Conclusion The failure to perform system maintenance in accordance with the specified MP, combined with the lack of specific work instructions, resulted in the inadvertent carbon dioxide discharge.
The discharge did not have a
significant effect on the safe operation of the facility.
The licensee has initiated a nonconformance report (NCR)
on this problem to investigate, determine, and correct the root cause of the problem.
The licensee's actions appear to adequately address the inspectors'oncerns that maintenance be performed in accordance with approved procedures.
OPERATIONAL SAFETY VERIFICATION (71707)
2. 1 Unit 1 Control Room Jum er Lo Deficiencies Background - The inspectors performed a review of the licensee's program for controlling temporary modifications and measurement and test equipment (M&TE).
Temporary modifications covered by this program include; lifted electrical leads, electrical jumpers, mechanical bypasses and M&TE.
The licensee's inter-departmental Administrative Procedure, CF4. ID7, Revision 0,
"Temporary Modifications - Plant Jumpers and M&TE," provided the method for ensuring proper engineering and safety reviews are performed prior to the installation of temporary modifications.
In addition, the procedure also provides a system for recording the installation of plant jumpers and M8TE available to the operators.
During the review of the Unit 1 records, the inspectors noted one instance in which the licensee had not completed the required actions of the procedure.
The deficiency is discussed in Sections 2.1.1.
The inspectors reviewed the Unit 1 jumper log and determined that there were a
total of 16 jumpers installed.
The inspectors observed that none of the jumpers appeared to bypass functions required by TS.
The inspectors noted that the licensee had recently written several action requests on jumper log deficiencies which were identified by the licensee during a recent review.
The number of deficiencies found during the reviews indicated that the monthly program reviews, specified in Section 4.3. l.c of Procedure CF4. ID7, Revision 0, had not been effective in identifying and resolving administrative discrepancies associated with the jumper log.
In response to the noted
deficiencies with the administrative controls associated with jumpers, the licensee is reviewing the procedure to determine areas where improvements can be implemented.
2.1.1 Periodic Walkdown of Installed Jumper Not Performed No problems were identified with most of the jumpers; however, the inspectors noted that the quarterly walkdown for a jumper associated with a drip flow element for Unit 1 feedwater heaters had not been performed as required by CF4. 107, Revision 0, Section 6.8.1.
Section 6 8.1 requires that the installing section perform a walkdown of the plant jumper every 92 days to verify the proper insta'llation, condition, and attached information tags.
Following identification of the discrepancy, the licensee performed a walkdown 128 days after installation and noted no deficiencies with the jumper.
The licensee documented this walkdown on the jumper log.
2. 1.3 Safety Significance This jumper was not installed on safety-related equipment.
The walkdown performed by the licensee following identification of the discrepancy did not identify any deficiencies with the jumper, therefore, this deficiency did not have an effect on the safe operation of equipment.
2. 1.4 Conclusion The inspectors did not identify a safety concern with the installation or control of jumpers.
The missed 92 day jumper walkdown and the jumper log deficiencies are examples of human performance weaknesses.
PLANT MAINTENANCE (62703)
During the inspection period, the inspectors observed and reviewed selected documentation associated with the maintenance and problem investigation activities listed below to verify compliance with regulatory requirements, compliance with administrative and MP, required quality assurance
{gA)/quality control department involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
Specifically, the inspectors reviewed the work documentation or witnessed portions of the following maintenance activities:
Unit i Inspection of 480 Volt Bus F Magnetic Contactors
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Component Cooling Water Train A
Unit 2
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AFW Pump 2-2 Recirculation Line Stop Valve (AFW-2-168) Replacement
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SG 2-3 AFW Level Control Valve (LCV) (AFW-2-LCV-108) Electrical Troubleshooting and Starting Line Contactor Replacement 3.1 AFW Pum 2-2 Recirculation Throttle Valve Failure Background During the performance of a routine pump surveillance test for motor-driven AFW Pump 2-2, the pump recirculation flow rate could not be reduced to the required value by throttling the recirculation throttle valve (Valve AFW-2-168).
Venting of the pump recirculation flow differential pressure (dP)
gauge and instrument lines had no effect on the indicated dP.
A test gauge was installed to measure recirculation flow to verify the accuracy of the installed gauge.
The measured dP read on the test gauge was in close agreement with the installed gauge dP readings.
Further attempts by the licensee to throttle recirculation flow were unsuccessful.
The minimum recirculation flow which could be obtained by throttling AFW-2-168 was 64 gpm.
The AFW pump surveillance test requires that the maximum recirculation f'low be less than 104 inches of water as read on the dP gauge.
This dP is equivalent to 51 gpm.
The basis for the maximum recirculation flow rate ensures that the required AFW flow is supplied to the SGs rather than being recirculated to the condensate storage tank.
Based upon the inability to adjust the recirculation flow within the acceptable range, the licensee declared AFW Pump 2-2 inoperable.
3. 1. 1 Licensee Evaluation of AFW Pump 2-2 Operability In the licensee's initial operability evaluation, the inability to throttle AFW pump 2-2 recirculation flow was attributed to either the separation of the valve disc and plug assembly, or the presence of a foreign object lodged under the valve seat.
Following the initial AFW pump surveillance, which revealed the problem, two partial surveillances were performed without attempting to adjust Valve AFW-2-168.
The results of the partial surveillances indicated that the evolution of starting, running, and stopping the pump did not result in an appreciable change in the recirculation flow rate.
The minimum flow to the SGs, as listed in both the TS Bases and the Final Safety Analysis Report, is 440 gpm divided equally between two SGs.
Westinghouse had previously performed an assessment of the safety acceptability of reduced motor-driven AFW pump flow rates, as documented in a letter to the licensee.
The calculation performed for the assessment indicated that the minimum required flow rate for a motor-driven AFW pump was 410 gpm divided equally between two SG '
The licensee previously performed AFW flow calculations which assumed AFW Pump 2-2 operation under design basis conditions.
These calculations determined the increase in AFW Pump 2-2 recirculation flow rate conditions based on recirculation flows measured during the surveillance.
The calculation results indicated a reduction of flow to the SGs of 17.4 gpm, The licensee conservatively assumed that 85 percent of the flow reduction would be from SG 2-1, even though past test results indicated that the flow resistances to each of the SGs were closely matched.
The calculated reduction in AFW flow did not reduce the flow below the minimum AFW requirements.
Based upon this evaluation the licensee declared AFW Pump 2-2 operable.
The inspectors reviewed the licensee's evaluation of AFW Pump 2-2 operability and determined that the conclusions appeared appropriate.
3.1.2 Radiography of AFW Pump 2-2 Recirculation Throttle Valve In order to obtain additional information regarding the operability of Valve AFW-2-168, the valve was radiographed.
The radiograph showed that the stellite disc had separated from the disc guide.
Radiography results showed the disc to be wedged in between the seat recess of the valve body and the disc guide.
The outer diameter of the disc was noted to be larger than the valve outlet port, which prevented the disc becoming dislodged and traveling downstream of the valve.
Subsequent investigation revealed that the disc had been attached to the disc guide with a square butt weld.
The size of the weld was approximately I/32" with no filler material.
Review of the valve design showed that the disc and disc guide plug assembly were not rigidly attached to the stem.
This design resulted in flow induced vibration of the stem disc assembly.
The licensee performed a metallurgical analysis of the failed weld which indicated that the cause of the failure was flow induced vibration fatigue.
As a part of the investigation, the licensee determined that the only other valve installed with the same manufacturer and model number was the TD AFW Pump 2-1 recirculation throttle valve (Valve AFW-2-132).
The licensee radiographed Valve AFW-2-132.
The radiography results indicated that the disc for Valve AFW-2-132 and the disc guide plug assembly were attached.
The licensee subsequently performed testing with the throttle valve fully open which revealed that the recirculation line orifice sufficiently limited recirculation flow to ensure adequate flow to the SGs
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3.1.3 AFW Pump 2-2 Recirculation Throttle Valve Repair The inspectors observed portions of the repairs to Valve AFW-2-168.
Prior to commencing the valve repair, the licensee established a carbon dioxide freeze seal jacket to isolate the AFW Pump 2-2 recirculation line from the condensate storage tank.
The inspectors reviewed the clearance established for the work and observed that it appeared to adequately isolate the maintenance area and had been established in accordance with the licensee's procedures.
The work order and HP for establishing and maintaining the freeze seal were also reviewed.
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-10-questioning one of the mechanical maintenance personnel maintaining the freeze seal, the inspectors noted that the individual was familiar with the requirements of the contingency plan which established the actions to be taken in the event of the failure of the freeze plug.
It was also noted that the personnel safety precautions for handling carbon dioxide specified in the licensee's MP M-54.3, Revision 5,
"Freeze Seal of Piping," were being complied with by the personnel maintaining freeze seal.
The inspectors observed the personnel involved with maintaining the freeze seal for a period of approximately 30 minutes and noted that the requirements of HP H-54.3 were not being followed in that the personnel maintaining the freeze seal were not performing 30 second injections of carbon dioxide to the freeze seal jacket every 15 minutes as required by MP H-54.3, Section 7.0.
The procedure required that these injections be performed as a safety precaution in order to keep the jacket filled with carbon dioxide snow until the work was completed.
After the inspectors questioned compliance with this procedural requirement, the 30 second injections were performed.
In discussions with the licensee personnel regarding the freeze seal, it was also noted that the mechanical maintenance personnel had verified that the contents of the pipe were frozen by the formation of a frost band on the outside edges of the freeze seal jacket.
MP M-54.3, Section 7.5.9.a, specified that the pipe temperature of -40 F or below would be representative of formation of the freeze seal.
Section 7.5.9.b required monitoring of the pipe temperature during the performance of the work to ensure that the freeze plug stayed frozen.
Discussions with the personnel indicated that it was not possible to measure the pipe temperature of the pipe under the freeze seal jacket, therefore, the monitoring of pipe temperature was not being performed.
The licensee is revising HP M-54.3 to clarify the requirements for monitoring and maintaining freeze seals.
The inspectors also observed a portion of the maintenance which involved lapping of the valve seat.
The inspectors noted that an initial satisfactory blue check was obtained despite several imperfections in the valve seat.
The licensee continued to lap the valve to further improve the blue check results after obtaining the initial satisfactory check.
3. 1 '
Safety Significance The failure to perform the required monitoring of the freeze did not present a
significant safety concern since mechanical maintenance personnel were continuously stationed at the work site during the work and were periodically monitoring the frost band on the outside edges of the freeze seal.
These actions provided assurance that the freeze plug was maintained during the work.
Additionally, the failure to perform the required injections of carbon dioxide to the freeze seal jacket did not appear to effect the ability of the jacket to maintain the freeze seal during the time that the inspectors observed the freeze sea.1.5 Conclusion The failure of the mechanical maintenance personnel to perform monitoring of the pipe temperature and the 30 second injections of carbon dioxide, both of which were actions required by the MP, are a violation of TS 6.8. 1.
TS 6.8. 1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978.
Appendix A of Regulatory Guide 1.33, Revision 2,
recommends that maintenance which can affect the performance of safety-related equipment should'e properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.
Contrary to the above, the procedure for monitoring and maintaining the freeze seal during the repair of Valve AFW-2-168 was not followed.
Although the noncompliance with the procedure in this instance did not create a safety concern, the inspectors noted that maintenance personnel chose not to comply with the established requirements rather than obtaining a change to the procedure.
This violation is not being cited because the criteria in paragraph VII.B.1 of Appendix C to
CFR Part 2 of the NRC's "Rules of Practice,"
were satisfied.
However, this is an example of weak human performance.
3.2 Valve AFW-2-LCV-108 Ma netic Contactor Re lacement Background - On June 6,
1995, when performing a surveillance test of the TD AFW Pump 1-1, the motor operated AFW discharge header SG 2-LCV, Valve AFW-2-LCV-108, failed to close.
Investigation by the licensee revealed that when attempting to remotely close the valve, the associated 480 volt circuit breaker thermal overload device tripped.
The licensee completed the surveillance by manually positioning Valve AFW-2-LCV-108 when valve operation was required by the procedure.
Following completion of the surveillance test, troubleshooting was conducted, which revealed that the
"C" phase contact of the magnetic contactor (AC line starter) failed to close.
The open contact interrupted power to the associated motor phase and prevented motor rotation.
Further inspection revealed that the "close" contactor arc box phase barrier was chipped adjacent to the
"C" phase contact.
The licensee determined that the cause of the thermal overload trip was due to a small piece of the phenolic material from the arc box breaking off and becoming wedged in the
"C" phase of the contactor.
The phenolic material prevented the
"C" phase contactor from closing, which effectively single phased the motor and caused the thermal overload device to actuate.
The damage to the magnetic contactor arc box was concluded to have been caused during the tightening of a terminal connection.
When tightening the terminal for the upper right stationary contact the conductor rotated and came in contact with the phase barrier material with sufficient force to cause cracking or breakage.
The broken chip of phenolic material became lodged between the stationary and moving contact and prevented the contact from closing.
This mechanism for failure potentially affected all Westinghouse
-12-Model A201K1CA size 00, 0, and 1 magnetic contactors.
Investigation by the licensee revealed that only size 1 contactors had been installed in safety-related applications at Diablo Canyon Power Plant (DCPP).
The licensee replaced the close contactor for Valve AFW-2-LCV-108.
After noting cracks on the open contactor for Valve AFW-2-LCV-108, it was also replaced.
Replacement contactors were a newer version of the same model Westinghouse magnetic contactor with a thicker phase barrier in the area where the cracking had been noted on the earlier version.
The licensee does not believe this version of the magnetic contactor to be susceptible to the phase barrier cracking experienced with the earlier version.
3.2.
Operability Evaluation of Magnetic Contactor Phase Barrier Cracking The licensee performed an initial prompt operability assessment of contactor operability and concluded that the likelihood of similar failures was low based upon the inservice time of the contactors without having noted a similar failure.
During a discussion which included the licensee's initial operability assessment of the magnetic contactors, the NRR project manager questioned the validity of the assessment since it appeared to be based solely upon the past operational history of the contactors.
The licensee subsequently performed a detailed operability assessment, which more thoroughly evaluated equipment operability with a cracked and/or chipped magnetic contactor phase barrier.
The evaluation addressed the potential for additional chipping of the phase barrier during normal contactor operation, the likelihood of the broken barrier compromising the effectiveness of the electrical insulation between contacts, as well as an evaluation of the safety function of each electrical class 1E component supplied by Westinghouse Model A201KICA size 1 magnetic contactors.
3.2.2 Magnetic Contactor Inspections As part of the licensee's evaluation of whether this problem affected other circuit breakers, the licensee performed a
100 percent inspection of all Westinghouse Model A201K1CA size 1 magnetic contactors installed in safety-related equipment.
The inspection involved a visual inspection to determine if the phase barrier material was chipped or cracked and as-found and as-left contactor continuity readings with the contactor manually overridden to close the contacts.
Prior to the inspection, during review of the work instructions, the inspectors questioned the licensee's reasoning for not obtaining as-found contactor continuity readings.
The inspectors noted that these readings were necessary in order to fully understand the effect of the phase barrier cracking on equipment operability.
Previously, during the initial inspection of the Valve LCV-108 close magnetic contactor, continuity readings were taken prior to removal of the phase barrier cover which indicated an open phase
"C" contact when the contactor.
Following the removal of the contactor cover the continuity reading taken across the
"C" phase contact indicated that the
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-13-contact was closed.
Based upon concerns for determining the as-found operability of equipment, the licensee revised the instructions to include as-found contactor readings as a part of the inspection.
Results from these readings indicated that there were no other instances where the phase barrier material chips prevented proper magnetic contactor operation.
The inspection results revealed a number of contactors with chips and/or cracks in the phase barrier material.
The licensee removed the phenolic material noted to be cracked and not securely bonded to the remaining material.
Inspections revealed the following numbers and percentages of magnetic contactors with cracked or chipped damaged phase barriers.
480 Volt Bus Number Ins ected Number with Oama e
Percenta e
Unit
Bus IIFII IIG II Bus "K"
61
26
27
%
%
%
Unit 2 II F II II G II Bus "K"
63
7
8 16 /
%
%
The licensee is evaluating the significantly greater occurrence of cracking and chipping of the phase barriers found on Unit 1.
3.2.3 Safety Significance Following the initial discovery of a potential generic issue involving the operability of magnetic contactors the licensee promptly initiated a thorough investigation which involved a
100 percent inspection of all suspect contactors installed in saFety-related equipment.
The results of the inspection identified numerous other magnetic contactors with damaged phase barriers; however, none of the magnetic contactors were found to have been inoperable.
The licensee has notified Westinghouse of the cracking of the phenolic phase barrier material with this model contactor.
The licensee's actions to remedy the problem appear to have provided reasonable assurance of component operability.
3.2.4 Conclusion The actions performed by the licensee following identification of the damaged magnetic contactor phase barrier, which prevented operation of the motor for AFW-2-LCY-108, were noteworthy.
The licensee demonstrated the appropriate concern for the prompt and thorough resolution of an equipment problem that appeared to create the potential for a common mode failur SURVEILLANCE OBSERVATIONS (61726)
Selected surveillance tests required to be performed by the TS were reviewed on a sampling basis to verify that:
(1) the surveillance tests were correctly included on the facility schedule; (2)
a technically adequate procedure existed for performance of the surveillance tests; (3) the surveillance tests had been performed at a frequency specified in the TS; and (4) test results satisfied acceptance criteria or were properly dispositioned.
Specifically, portions of the following survei llances were observed by the inspectors during this inspection period:
Unit
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Surveillance Test Procedure (STP)
P-AFW-11,
"Routine Surveillance Test of TD AFW Pump 1-1"
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STP V-3R5, "Exercising Steam Supply to AFW Pump Turbine Stop Valve, FCV-95"
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STP V-3S2, "Exercising Phase A Containment Isolation Valves (SG Blowdown)"
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STP V-3P5, "Exercising and Timing of Valves LCV-106, 107, 108 and 109 AFW Pump Discharge"
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STP V-3R6, "Exercising Steam Supply to AFW Pump Turbine Isolation Valves" Unit 2
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STP I-2D, "Nuclear Power Range Incore/Excore Calibration"
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STP P-AFW-21, "Routine Surveillance Test of TD AFW Pump 2-1" 4. 1 Routine Surveillance Test of TD AFW Pum 1-1 Background -
On June 6,
1995, the inspectors observed the performance of a cold start of the Unit
TD AFW Pump 1-1.
The licensee's surveillance procedure requires that a cold start be performed on a quarterly basis.
During the test the TD AFW pump was remotely started from the control room by manually opening the TD AFW pump steam supply stop Valve FCV-95.
4.1.1 Surveillance Requirements for Determining Turbine Speed The Surveillance Procedure Section 12.13 required measuring the as-found speed of the turbine after starting AFW Pump 1-1.
This step did not provide any guidance to the operators for the time period that this measurement should be made within following the turbine start.
Section 12. 16 of the procedure
-15-recognized that during pump operation as the temperature of the governor oil increases the pump speed may drift down.
The inspectors noted that failure to specify the time at which the speed should be measured could result in inconsistencies in turbine speed measurements during the surveillances and additional governor adjustments.
The pump speed is also measured during a subsequent step of the surveillance prior to verifying that the pump recirculation flow rate is within the acceptable limits.
The inspectors noted that during the performance of the test operators adjusted the speed during step 12. 16 and then subsequently prior to installing the locking device on the recirculation flow in Section 12. 18 F 1 after it was noted that the speed had drifted below the specified band of 4150 +/-10 rpm.
The procedure did not provide any specific guidance in Section 12. 18. 1 to perform turbine speed adjustment.
The inspectors noted that the procedural requirements for measuring and adjusting turbine speed did not appear to assure accurate adjustment of the TD AFW pump recirculation flow rate.
The inspectors discussed these concerns with the system engineer who indicated that the surveillance procedure was being reviewed to determine where procedural improvements could be made to ensure accurate measurements of both turbine speed and recirculation flow.
The inspectors concluded that the recirculation flow had been properly adjusted during the surveillance.
4. 1.2 TD AFW Pump 1-1 Fan Blade Cracking During the surveillance an operator performing the test noted that the outboard end-bearing cooler fan had several cracked fan blades.
Further inspection by the licensee revealed that four blades were distorted, two of which were also cracked.
A total of three blades were noted to have cracks.
A small amount of oxidation and corrosion was noted in the cracks which indicated that the cracking had occurred some time ago.
The fan itself is an aluminum casting with eight radial blades.
The fan blades are connected to each other by a backing ring approximately 1 inch wide.
Based upon the one-piece cast construction the licensee concluded that it was unlikely that the backing ring would separate from the fan hub.
Both the TD motor-driven AFW pumps have the same type of shaft driven bearing cooler fan on both the inboard and outboard bearing housings.
The licensee performed an inspection of all fan blades for both Units 1 and 2. During the inspections no blade cracking or distortion was found on any other fan blades.
A shroud, which is installed over the fan blade, directs air flow around the bearing housing and precludes any foreign objects from falling into the fan during operation.
The licensee determined, based upon the damage to the blades without damage to the housing, that the fan blade damage had most likely occurred during maintenance accomplished when the shroud was removed.
The licensee last worked on the pump when the fan shroud was replaced in
-16-May 1994.
Additionally, since there was no evidence of cracking on the other five blades, the damage to the fan appears to be from impact and not cyclical fatigue.
The licensee's operability evaluation assumed that the damage had occurred during the last maintenance in May 1994.
Since that time the AFW pump had a
minimum of 12 surveillances performed where the pump had been run for an average of 40 minutes.
Additionally, the pump started and operated following a reactor trip in December 1994.
The licensee concluded that the fan was not in imminent danger of failing based upon the pump operation during the past year.
As a result of the damage to the fan, the licensee has established compensatory actions, which include inspection of the fan blades following each pump operation, and additional annunciator response for a bearing high temperature alarm to assure adequate bearing cooling.
The licensee plans to replace the fan at the earliest available opportunity.
4. 1.3 Safety Significance The licensee's assessment of the fan blade damage appeared to consider all potential failure mechanisms.
Additional compensatory actions placed into effect appeared to adequately provide information required to evaluate any further propagation of the fan blade cracks.
The licensee determined that in the unlikely event of fan failure that the potential imbalance of the pump would not effect pump operability and that a control room alarm would alert operators of the need to provide alternate cooling in the event of a bearing cooling alarm.
4.1.4 Conclusion The inspectors considered the licensee's investigative actions to have been thorough and appeared to adequately address the potential effect of the degraded fan blades on pump operability.
ONSITE ENGINEERING (37551)
5. 1 Personnel Errors Durin Containment Penetration Isolation Valve Leak
~Teetin Background - On May 19, 1995, Unit 1 containment was purged.
Following completion of the purge, the Shift Technical Advisor contacted engineering to perform the leak test of the penetration containment isolation valve
{Valve VAC-1-FCV-662), which was operated to accomplish the purge.
TS 4.6.3.4 requires that each containment valve be demonstrated operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after closing the valve by performing a test which measures and verifies the valve leak rate less than the maximum acceptable value.
The engineer performing the test obtained the Unit 1 Shift Foreman approval for performing the test and caution tags were hung on the control switches,
-17-for valves were required to be closed for the performance of the test.
The engineer performing the test incorrectly went to the Unit 2 ventilation containment penetration area and performed a leak test of the Unit 2 Valve VAC-2-FCV-662.
Upon completion of the testing, the engineer returned to the control room at which point the fact that the wrong unit had been tested was discovered.
Following discovery of the testing error, the Unit 1 penetration containment isolation valve was tested satisfactorily within the TS prescribed time limit for testing.
The procedure clearly indicated the valves which were required to be operated or verified as being Unit 1 valves.
The methods established for self verification were not used by personnel performing the testing.
Additionally, two individuals performing independent verification of the position of a test valve failed to note that the wrong valve was being operated.
5.1.1 Safety Significance The error was discovered immediately following the completion of the test and the required testing was then satisfactorily accomplished within the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of closing the valve, as required by TS.
The test results showed that the valve had been operable.
5.1.2 Conclusion Although in this instance the prompt identification and correction of the testing errors prevented this issue from having an impact on safety, testing the incorrect containment penetration isolation valve is of concern to the NRC in that management has placed an emphasis on self-verification to prevent personnel errors, and there were opportunities for others to have identified the error.
The licensee has initiated an NCR on this problem and is further researching the corrective actions to prevent recurrence of this type of problem.
5.2 Safet Assessment and ualit Verification The safety assessment and quality verification programs were reviewed to determine the current status of the licensee's programs for gA, quality control, and the ISEG.
5.2.1 equality Performance Assessment Report ((PAR)(Fourth ()uarter 1994)
The (PAR was issued quarterly by Nuclear guali iy Service (NQS)
and evaluated each area of plant management.
The assessment identified several well directed evaluations of licensee organizations.
Evaluations and conclusions appeared to have been substantiated with several observations.
Items of particular note have been an improvement in procedure adherence and use.
Personnel errors in Operations Services was an area of concern with a
recommendation that closer management attention on reducing personnel errors
-18-was warranted.
This concern was backed up with several examples including the grounding buggy installation, the loss of residual heat removal (RHR) during diesel generator (DG) testing, and the primary to secondary dP limit being exceeded during the reactor coolant system cooldown prior to the 2R6 refueling outage.
The (PAR also made a request for close management attention to pursue the root cause of radioactive material being found outside the radiological controlled area.
This was highlighted in the (PAR with particular emphasis on the observation that corrective action was being taken without Plant Safety Review Committee (PSRC)
review and approval.
The /PAR also noted that the NCR on the issue was not being pursued in a timely manner.
Conclusion The inspectors concluded that the (PAR was effective and provided valuable insights to effect improvement.
The (PAR was proactive and direct in tone lending credibility to the findings.
The requested actions were reasoned and reflected a strong position on the part of NgS.
5.2.2 Audits Performed by NgS The inspectors reviewed several audits performed by the N(S.
Audits reviewed by the inspectors included the following:
~
Audit 950011,
"Training and (qualifications of Plant Staff, Including INPO Accreditation Renewal Supporting Technical Issues"
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Audit 950031,
"Regulatory Design Services Licensing and Design Basis Hanagement"
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Audit 950071,
"Annual Fire Protection and Loss Prevention Audit"
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Audit 950101,
"DCPP Radiological Effluents and Offsite Dose Calculation Procedure"
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Audit 950121,
"Procurement" Summary The audits reviewed were applied to safety-related areas, and appeared to have been well directed to identify problems.
The problems identified were insightful, and findings were performance based.
Each problem identified during an audit was documented on a formal problem identification document, and resolved in accordance with problem resolution schedules.
Host problems identified during audits were promptly addressed by the line organization.
Safety Significance - The findings of N()S were of varying significance.
They have been or are being resolved consistent with their safety significance.
None of the findings have been dropped.
For the few instances where the line organization had not provided a satisfactory or timely resolution, the matter had been brought to licensee management attentio Conclusion The audits reviewed were of significant strength, and identified several noteworthy findings.
Many problems identified by audits have been promptly resolved.
The NRC will continue to follow the licensee's resolution of issues which are elevated to management attention.
5.2.3 ISEG The inspectors examined evaluations made by the ISEG and determined that they included identification of specific and programmatic concerns, as well as root cause evaluations and evaluations of corrective actions.
The evaluations recommended areas of increased focus, management action, and suggested resolutions, when appropriate.
The inspectors reviewed the following ISEG reports:
ISEG Evaluation 95-003, "Activities Affecting DG Air Flow"
~
Draft ISEG Evaluation,
"Clearance and Tagging Processes" The inspectors interviewed the ISEG supervisor about the program including his assessment of past performance and plans for the next few months.
The ISEG performance For the period of the last 6 months included reviews of the 2R6 refueling outage and systematic reviews of other plant activities.
The group has also been active in evaluating industry trends and reports.
The ISEG is also working to provide suggestions and observations that contribute to the resolution of concerns raised by the group.
This is an initiative taken to improve the credibility oF the ISEG among the other site organizations.
While there is no direct evidence that the initiative is working, the inspectors noted that it appears to be a positive contribution.
Conclusion The ISEG involvement in plant processes was probing, and provided an excellent snapshot of issues for which ISEG involvement resulted in plant safety improvements.
The ISEG was effective in identifying problems, particularly in areas requiring a broad perspective.
The NRC wi 11 continue to follow licensee management involvement in ISEG identified issues.
5.2.4 gA Surveillance A gA surveillance is an audit of abbreviated scope to quickly assess an area, and which may result in additional resources being applied to that area of inspection.
The inspectors reviewed each of the following surveillances by N(S:
Surveillance Report gA-95-0006,
"Design Change Notice Closure and Completion Processing" Surveillance Report gA-95-0010,
"Software gA Surveillance Report gA-95-0011,
"Use of 'Whiteout'nd Correct'ion Tape"
-20-
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Surveillance Report QA-95-0016,
"Maintenance of AFW Pp l-l And Support Equipment"
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Surveillance Report QA-95-0017,
"Replacement of Safety Injection Pump 2-2
~
Surveillance Reports QA-95-0019 and QA-95-0020, "Fire Watch Surveil'lances" The surveillances appeared appropriate in scope and were performance based.
The auditors were prepared and identified performance based findings.
The auditors documented the findings, and recommended followup actions where necessary.
Conclusion - The surveillance program is a flexible tool to quickly assess areas not traditionally required for full scale audits.
These surveillances have provided valuable assessments in a timely manner, and are a quality program strength.
5.2.5 NCRs The inspectors reviewed a sample of six NCRs.
In all cases, the reports addressed the problem and, for cases where the root cause was not clearly evident, multiple corrective actions were implemented.
Some of the NCRs were not yet closed; however, many corrective actions had already been implemented.
This is a continuing issue, having been raised by NQS previously.
The inspectors noted a wide variation continues in timeliness of resolution of the NCRs.
Hanagement involvement in the more significant NCRs was evident from the reviews by the inspectors.
Conclusion The NCR process is effective, flexible, and appears to address problems appropriately, although evidencing wide variation in timeliness of corrective action.
5.2.6 Overall Conclusion The inspectors concluded that the nuclear oversight organizations were providing substantial contributions to the improved effectiveness of activities at Diablo Canyon and plant safety.
PLANT SUPPORT ACTIVITIES (71750)
The inspectors evaluated plant support activities based on observation of work activities, review of records, and facility tours.
The inspectors noted the following during these evaluation ~
~
~
~
-21-6.1 Emer enc Li htin Background - In December 1990, during its Appendix R Design Basis Documentation Enhancement Project and a self-assessment of DCPP fire hazards safe shutdown analysis, the licensee found emergency lighting deficiencies in number of plant areas.
In July 1992, the licensee informed the NRC of its findings and proposed actions in LER 323/92-001-02, including making flashlights available for operator use in the event of a fire.
Subsequently, in a submittal dated Harch 15,.1994, the licensee requested an exemption from the technical requirements of Section III.J of Appendix R to
CFR Part 50 to the extent that it requires that emergency lighting units with at least an 8-hour battery power supply be provided for the access and egress routes to all areas needed for the operation of safe shutdown equipment.'ince the LER was issued, the licensee implemented compensatory measures of hand-held portable lights (flashlights) for use in the access and egress pathways.
The extended duration for which compensatory actions are in effect and the delay until 1994 in proposing a long term fix to the problem represent slow resolution of this matter.
By letter dated Hay 5, 1995, the staff denied the licensee's exemption/deviation request because the need to obtain flashlights before control room evacuation and to carry and use the flashlights under the stressful and unusual conditions of a fire emergency would place burdens on the plant operators.
By letter dated Hay 9, 1995, the licensee committed to install battery-operated lights in the remaining access and egress pathways by the end of the next refueling outage for each unit.
The compensatory measures will remain in effect until the lights are operational.
6.1.1 Safety Significance One significant objective of fixed emergency lighting units is to provide direction to the operators if electrical power is lost as a result of a fire and to provide reasonable assurance that operators will not become disoriented, especially in stairwells and at doorways and intersecting corridors.
The lack of fixed emergency lighting in some routes could contribute to operator confusion and impact the timely completion of manual operator actions.
Further, the flashlight beam cannot provide coverage and illumination levels equivalent to that of fixed emergency lighting.
Depending on the direction of the flashlight beam, the operator may not observe any obstructions not normally present (related or unrelated to the fire).
It is not possible to predict the specific condi.tions under which fires may occur and propagate.
Therefore, it is not possible to predict how much time the operators will spend in access and egress pathways that do not contain fixed lighting.
Thus, the life of the flashlight batteries may not be
'he request should have been for a deviation from a license condition because the licensee is not an Appendix R plant, but committed to Appendix R
through the DCPP approved fire protection program referenced in the license conditio sufficient to cover these periods of time.
Also, there is not reasonable assurance that a flashlight would remain in the possession of the operator and functional throughout the fire event.
6. 1.2 Conclusion The underlying purpose and intent of Section III.J of Appendix R is to provide fixed emergency lighting units of sufficient duration to eliminate the availability of a light source as an element requiring operator consideration when responding to a fire emergency that requires plant shutdown.
The licensee was slow in presenting its long term proposal to the NRC and continues to implement compensatory actions.
The licensee's desire for permanent use of flashlights instead of fixed emergency lights does not satisfy this purpose or intent.
The licensee failed to maintain all provisions of the approved fire protection program (which includes adherence to Section III.J) in accordance with License Condition 2.C.(5).
Because this violation meets the criteria of Section VII.B.(2) of the Enforcement Policy, this violation was not cited.
FOLLOWUP PLANT OPERATIONS (92901)
7.1 Closed Violation 323 95-02 Failure to Follow Procedural Re uirements for 0 eration of the Reactor Tri B
ass Breakers The violation cited the failure of operators to perform reactor trip breaker bypass operations in accordance with procedural requirements.
The violation also noted that procedural requirements for concurrent verification had not been performed properly.
The inspectors reviewed the licensee's response to the violation and determined that the corrective actions initiated, which included communication of management expectations to operations personnel for procedural compliance, concurrent verification and shift management involvement in plant activities, revision of the procedure for reactor trip and bypass breaker operation, and human error reduction training, appeared to address the correction of the root cause of the violation.
Based upon this review, the violation is closed.
FOLLOWUP ENGINEERING (92903)
8. I Closed Unresolved Items 275 95-02 and 323 95-02 SSPS Desi n
Vulnerabilit to NSLB An electrical vulnerability in the SSPS power supply, was identified by the licensee's engineering staff during resolution of a design basis reconstruction concern.
The licensee's review found that the SSPS input circuitry could be electrically grounded during an HSLB, and the resulting blown fuses would remove power from engineered safety feature (ESF) actuation logic circuitry.
A reactor trip would occur upon loss of power, but one train of automatic ESF actuation would be inoperable.
In the event of a single
-23-failure on the other ESF train, no automatic ESF functions would be available, although operator actuation of individual equipment items would remain operable.
The design vulnerability was promptly communicated to licensee management, who discussed them with the NRC.
The licensee requested and was granted enforcement discretion to not enforce the TS requirements for automatic ESF actuation during the length of time required to install a design change to correct the vulnerability for all nonsafety-related input circuits.
The design change was accomplished without any problems.
Conclusion The existence of inadequate electrical separation between safety-related and nonsafety-related circuits is considered to be a violation of
CFR Part 50, Appendix A, Criteria 21, which requires that postulated accident conditions not result in a loss of the protection function, assuming a single failure.
The licensee aggressively evaluated this potentially significant issue, communicated with the industry in a timely manner, and aggressively implemented corrective actions.
Based upon the actions taken by the licensee, this violation is not being cited because the criteria in paragraph VII.B.2 of Appendix C to
CFR Part 2 of the NRC's "Rules of Practice,"
were satisfied.
IN OFFICE REVIEW OF LERs {90712)
The inspectors performed a review of the following LERs associated with operating events.
Based on the information provided in the report, review of associated documents, and interviews with cognizant licensee personnel, the inspectors concluded that the licensee had met the reporting requirements, addressed root causes, and taken appropriate corrective actions.
The following LER was closed:
~
323/95-001, Revision 0, TS 3.6.1.3 Not Met Due to Personnel-Error 9.1 Closed LER 275 94-015 Revision 0 and Revision
Failure to Im lement RHR S stem Over ressure Protection Re uirements due to Insufficient Desi n Basis Information The licensee determined the root cause of the condition to be insufficient design basis information for the RHR system.
The result was that the overpressure protection requirements would not be met during normal and postulated transient conditions in Mode 4 and 5 with the loops filled.
The vendor design basis information was inadequate regarding ASME Code overpressure requirements.
The licensee's analysis of the condition revealed that the 600 psig design pressure could be exceeded during normal operation of the heat exchangers and pumps (approximately 612 psig and 623 psig, respectively).
The maximum transient pressures were determined to be approximately 687 psig and 698, respectively.
These pressures are within the
a C
-24-inservice test pressure of 750 psig and the hydrostatic test pressure of 900 psig.
The licensee postulated that damage under these conditions is not likely to occur.
The licensee's immediate corrective actions included instructions to the operators regarding the engineering determinations and the need to assure adequate flow to ensure that the heat exchanger is protected from exceeding its maximum design pressure in Modes 4 and S.
The licensee's engineering organization will revise the RHR design criteria memorandum to include the requirement to regarding overpressure protection during Mode 4 and S
operation.
The licensee has also indicated that a design change will be pursued to increase the design pressure of the RHR system components such that all applicable Code requirements will be met.
9.2 Closed LER 275 94-017 Revision 0 and Revision I
DG Ventilation S stem Air Flow Potentiall Outside Desi n Basis Oue to Inade uate Desi n
The licensee completed the analysis of the functional requirements for the OGs with regards to cooling system operation during operation with high ambient air temperature.
The analysis concluded that the DG can carry the required loading at ambient temperatures up to 83'F.
The analysis was done using worst case conditions that included a 195'F maximum jacket water temperature, a
25-mph wind directly impinging on the exhaust louvers, zero percent recirculation air flow, and 600 gpm jacket water flow through the radiator core.
To ensure that the OG will perform at the design temperature of 90'F the licensee has installed an alarm (PK 15-05,
"Outdoor Ambient Air High Temperature" ) that annunciates at 83'F, less instrument inaccuracies.
When this alarm actuates, the licensee will institute the hot weather plan.
The plan requires that the roll-up fire doors to each OG be opened and a fire watch be established.
DG loads will be reduced commensurate with overheating concerns.
The inspectors noted in the review of the licensee's actions that the likelihood of exceeding 90'F at the site is quite low.
Temperatures over 78'F occur at the site no more than 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> per year.
The calculated increase in core damage frequency is not expected to be more that O.l percent.
The licensee is pursuing a design change that wi'l'l reduce the air flow resistance such that the DGs will have more margin For operating with the roll-up doors close C4 a
ATTACHMENT I
PERSONS CONTACTED 1.1 Licensee Personnel G.
H. Rueger, Senior Vice President and General Manager, Nuclear Power Generation Business Unit W.
H. Fujimoto, Vice President and Plant Manager, Diablo Canyon Operations L. F.
Womack, Vice President, Nuclear Technical Services H. J.
Angus, Manager, Regulatory and Design Services W.
D. Barkhuff, Engineer, Mechanical Haintenance J.
R. Becker, Director, Operations K. H. Bych, Senior Engineer, Independent Safety Evaluation Group M.
G.
Coward, Engineer, Secondary Systems Engineering W.
G ~ Crockett, Manager, Engineering Services R.
N. Curb, Manager, Outage Services T.
F. Fetterman, Director, Electrical and Instrumentation and Control Systems Engineering T. L. Grebel, Director, NRC Regulatory Support C. 0. Harbor, Engineer, Regulatory Support K. H. Kaminski, Engineer, Technical Maintenance 0.
B. Miklush, Manager, Operations Services J.
E. Holden, Manager, Maintenance Services P.
T. Nugent, Engineer, Regulatory Support 0.
H. Oatley, Director, Mechanical Maintenance R.
P.
Powers, Hanager, equality Services H. J. Phillips, Director, Technical Maintenance J.
A. Shoulders, Director, Engineering Services R. A. Waltos, Director, Balance of Plant Engineering 1.2 NRC Personnel
- K. E.
- H. 0.
- G.
W.
H. A.
- 0. E.
Perkins, Director, Walnut Creek Field Office Tschiltz, Senior Resident Inspector Johnston, Senior Project Inspector Hiller, Senior Project Manager Corporandy, Project Inspector
- Denotes those attending the exit meeting or participating via telephone conference during on May 18, 1995.
In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
EXIT MEETING An exit meeting was conducted on June 29, 1995.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee acknowledged the inspection findings documented in this report.
The licensee did not identify as proprietary any information provided to, or reviewed by, the inspector ATTACHNENT 2 ACRONYHS AFW CW DCPP DG dp ESF FCV ISEG LCV LER
%TE NP NSLB NCR NQS QA QPAR RHR
.
SG SSPS STP TD TS auxiliary feedwater circulating water Diablo Canyon Power Plant diesel generator differential pressure engineered safety feature flow control valve Independent Safety Evaluation Group level control valve licensee event report measurement and test equipment maintenance procedure main steam line break nonconformance report Nuclear Quality Service quality assurance Quality Performance Assessment Report residual heat removal steam generator solid state protection system surveillance test procedure turbine-driven Technical Specification
.A
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