IR 05000275/1993034
| ML16342A409 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/26/1994 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16342A408 | List: |
| References | |
| 50-275-93-34, 50-323-93-34, NUDOCS 9402230072 | |
| Download: ML16342A409 (28) | |
Text
U.S.
NUCLEAR REGULATORY COHMISSION
REGION V
Report Nos:
Docket Nos:
License..Nos:
Licensee:
Faci 1 ity Name:
~ Inspection at:
50-275/93-34 and 50-323/93-34 50-275 and 50-323 DPR-80 and DPR-82 Pacific Gas'nd Electric Company Nuclear Power Generation, B14A 77 Beale Street, Room 1451 P. 0.
Box 770000 San Francisco, California 94177 Diablo Canyon Units 1 and
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
December 9,
1993, through January 12, 1994 Inspectors:
H. Hiller, Senior Resident Inspector H. Tschi ltz, Resident Inspector J. Winton, Reactor Inspector Approved by:
~Summa@:
P.
H.
o son, Chief Reacto rojects Branch
Date Signed Ins ection on December
1993 throu h Januar
1994 Re ort Nos.
50-275 93-34 and 50-323 93-34 Areas Ins ected:
Routine, announced, resident inspection of plant operations; maintenance and surveillance activities; followup of onsite events, open items, and licensee event reports (LERs); and selected independent inspection activities.
Inspection Procedures 41500, 61726, 62703, 71707, 90712, 92701, and 93702 were used as guidance during this inspection.
Safet Issues Hang ement-S stem SIHS Items:
None Results:
General Conclusions on Stren ths and Weaknesses:
Strengths:
~
Plant operators demonstrated good safety awareness and appropriate immediate actions in responding to the event and preventing overcooling following a turbine/reactor trip on December 26, 1993 (Paragraph 4.a).
9402230072 940127 PDR ADOCK 05000275 Q
Weaknesses:
~
Following the Unit 1 trip on December 26, 1993, the identification and correction of equipment problems was hampered by initially insufficient or inaccurate information regarding equipme'nt malfunctions which were encountered (Paragraph 4.a).
~
The licensee's December 18,'993 request for enforcement discretion, although technically adequate, was weak in implementation of the specific guidelines and jnteractions applicable to the process (Paragraph 4.d).
Si nificant Safet Matters:
None Summar of Violations:
One non-cited violation (NCV) was noted regarding the fretting of component cooling water (CCW) heat exchanger tubes.
The licensee identified NCV involved the failure to ensure that the CCW heat exchangers were operated within their design flow rates (Paragraph 8).
DETAILS Persons Contacted Pacific Gas and Electric Com an C
G.
H.
- J.
D.
W. H.
- R. P.
J.
S.
J.
R.
- T. A.
D.
H.
- S.
G.
- L. L.
- W.. G.
S.
R.
T. L.
B.
W.
- R.
W.
- J.
R.
- K. A.
- D. B.
J.
E.
- T. A.
S.
R.
D. V.
P.
G.
D.
P.
- D. A.
Rueger, Senior Vice President and General Manager, Nuclear Power Generation Business Unit
Townsend, Vice President and Plant Manager, Diablo Canyon Operati'ons Fujimoto, Vice President, Nuclear Technical Services Powers, Hanager, Nuclear guality Services Bard, Director, Hechanical Maintenance Becker, Dayshift Supervisor,.Operations Bennett, Director, Outage Management Behnke, Senior Engineer, Regulatory Compliance Chesnut, Reactor Engineer Supervisor Cossette, Senior Engineer, Plant Engineering Crockett, Manager, Technical and Support Services Fridley, Director, Operations Grebel, Supervisor, Regulatory Compliance Giffin, Hanager, Maintenance Services Hess, Assistant Director, Onsite Nuclear Engineering Services Hinds, Director, Nuclear Safety Engineering Hubbard, 'Engineer, Regulatory Compliance Miklush, Manager, Operations Services'olden, Director, Instrumentation and Controls Houlia, Assistant to Vice President, Plant Management Ortore, Director, Electrical Maintenance Pierce, Senior Engineer, Hechanical Maintenance Sarafian, Senior Engineer, Nuclear guality Services Sisk, Senior Engineer, Regulatory Compliance Taggart, Director, Onsite guality Assurance
- Denotes those attending the exit interview.
The inspectors also interviewed other licensee employees, including shift supervisors, shift foremen, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, and quality assurance personnel.
0 erational Status of Diablo Can on Units
and
During this inspection period, Unit 1 operated at 100 percent power except for a power reduction for condenser cleaning on December
and 17, 1993, and an outage of approximately five days following a trip (Paragraph 4.a)
on December 26.
Unit 2 operated at 100K power during the report period except for three brief power reductions for condenser cleaning and other circulating water system maintenanc.
0 erati onal Sa fet Verification 71707
'a ~
General During the inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facility.
The observations and examinations of those activities were conducted on a daily, weekly or monthly basis.
On a daily basis, the inspectors observed control room activities to verify compliance with selected Limiting Conditions for Operation (LCOs)
as prescribed in the facility Technical Specifications (TS).
Logs,. instrumentation, recorder traces, and other operational records were examined to obtain information on pla'nt conditions and to evaluate trends.
This operational information was then evaluated to determine whether regulatory requirements were satisfied.
Shift turnovers were observed on a sampling basis to verify that all pertinent information on plant status was relayed to the oncoming crew.
During each week, the inspectors toured accessible areas of the facility to observe the following:
(I)
General plant and equipment conditions, (2)
Fire hazards and fire fighting equipment (3)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures (4)
Interiors of electrical and control panels (5)
Plant housekeeping and cleanliness (6)
Engineered safety features equipment alignment and conditions (7)
Storage of pressurized gas bottles The inspectors talked with control room operators and other plant personnel.
The discussions centered on pertinent topics of general plant conditions, procedures, security, training, and other aspects of the work activities.
b.
Radiolo ical Protection The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors verified that health physics supervisors and technicians conducted frequent plant tours to observe activities in progress and were aware of significant plant activities, particularly those related to radio-logical conditions and/or challenges.'LARA considerations were found to be an integral part of each RWP (Radiation Work Permit).
C.
Ph sical Securit Security activities were observed for conformance with regulatory requirements, the site security plan, and administrative procedures, including vehicle and personnel access screening, personnel badging, site security force manning, compensatory measures, and protected and vital area integrity.
Exterior lighting was checked during backshift inspections.
No violations or deviations were identified.
Onsite Event Follow-u 93702 a ~
Tri of Unit
Oue to Hain Generator Tri Circuit Com onent Failure On December 26, 1993, at approximately 2:22 p.m.,
an electrical disturbance occurred in the off-site power distribution system which
., created a electrical transient on the 500 KV distribution lines connected to both Units 1 and 2 main transformers.
Unit 2 was not affected by -the electrical
'system disturbance.
In Unit 1, however, the disturbance resulted in a main generator/turbine trip followed by a reactor trip.
The operators subsequently stabilized the plant in Hode 3, in accordance with Emergency Operating Procedures.
At 2:58 p.m., the licensee made a four-hour non-emergency report to the NRC per
CFR 50.72.(b).2 to report the automatic actuation of the reactor protection system.
All safety-related equipment functioned as expected with the exception of the position indication for steam generator 1-4 main steam isolation bypass valve FCV-22, discussed in detail later in this section.
Several minutes after the trip, the operators shut the main steam isolation valves (HSIVs) to reduce plant'ooldown and the resultant decrease in reactor coolant system (RCS) pressure.
RCS pressure decreased to 1926 psig.
Emergency Operating Procedures (EOPs)
were followed; however, subsequent to the initial EOP-required evaluation of the RCS temperature trend, RCS temperature decreased to the point where additional actions were required to prevent excessive cooling and RCS depressurization.
The cooldown and the resultant decrease in pressure were attributed to the combined cooling effects of auxiliary feedwater (AFW) addition to the steam generators and a
failed moisture separator reheater (HSR) steam control valve posi-tioner.
Failure of the HSR control valve positioner prevented HSR valve FCV-401 from closing, which resulted in a significant amount of steam flow to HSR 1-2A high pressure tube'undles.
The operators reduced AFW flow rate just prior to shutting the HSIVs to limit the cooldown.
Steam flow to HSR 1-2A was manually isolated after shutting the HSIVs.
The information gathered in the investigation of the plant cooldown was being included in operator training to familiarize operators with plant response for similar conditions.
Additionally, simulator modeling was being verified to ensur'e the simulator accurately models plant response for auxiliary feedwater addition to the steam generator The main generator/turbine trip was caused by the generator field voltage regulator instantaneous overcurrent relay circuit trip signal.
The increased current in the voltage regulator was caused by the voltage regulator's reaction to the 500 KV system disturbance during which system voltage and frequency decreased.
Troubleshoot-ing of the instantaneous overcurrent trip components identified a
failed isolation transducer in the circuit.
The transducer failure had the effect of reducing the setpoint of the protective overcur-rent trip associated with the voltage regulator.
The voltage regulator's response to the reduced grid voltage combined with the effect of the failed isolation transducer caused the trip signal.
The inspector followed the licensee's investigation of the reactor trip along with several other minor equipment problems which occurred during the trip recovery.
Licensee troubleshooting and subsequent corrective actions were delayed while the Operations staff provided additional description of equipment problems following the trip.
Specifically, initial information provided by Operations personnel on the following equipment problems was later found to be inaccurate:
~
The feedwater pump 1-2 turbine low pressure stop valve ini-tially was reported to have failed to fully close.
Subsequent investigation revealed that the valve did completely close and had been verified locally at the valve by an operator.
The licensee concluded that the position indicator, which initially showed the valve to be in the intermediate position (i.e., both open and shut lights lighted),
had malfunctioned.
The problem.
could not be duplicated during troubleshooting.
FCV-22 was initially reported to have failed to manually close.
Subsequent investigation revealed that the valve had fully closed and that the problem was with the position indicator which, after. initial closure of the valve, indicated the valve to be in the intermediate position (i.e.,
both open and shut lights lighted).
Operators had noted that the indication changed to show the valve was closed without any other action being taken.
This position indicator problem also could not be duplicated during troubleshooting, so the position indicator was replaced.
~
Hoisture Separator 1-2A high pressure tube bundle steam supply valve FCV-401 was initially reported to have been manually
"jacked open".
Subsequent investigation revealed that the valve was not "jacked open" and that a failed valve positioner had prevented the valve from closing.
The valve positioner was repaired.
The resultant troubl'eshooting of equipment based on the initially inaccurate equipment information led to a temporary misunderstanding of conditions by both maintenance and management personnel and delayed resolution of the problems.
The inspectors will assess the licensee's analysis and corrective actions for this event during review of the associated Licensee Event Repor b.
Letdown Isolation Valve Actuator Dia hra m Failure During the Unit 1'utage on December 27, 1993, while Unit 1 was in Mode 3, the letdown isolation valve (CVCS-1-LCV-460) closed due to a
rupture of the valve's actuator diaphragm, resulting in isolation of normal letdown flow.
Excess letdown was placed in service during the time period normal letdown was isolated.
All electrical inter-locks, appeared to be met to allow re-opening of CVCS-1-LCV-460; however, the valve would not reopen when the control switch was repositioned.
Investigation revealed that the CVCS-1-LCV-460 actuator diaphragm had ruptured, allowing actuator spring force, without any opposition force from the actuator diaphragm, to close the valve.
c ~
After replacement of the actuator diaphragm, during post-maintenance testing of the actuator, CVCS-1-LCV-460 would not open.
The actuator was then disconnected from the valve arid verified to be operating properly, indicating that the valve was stuck in the closed position.
CVCS-1-LCV-460 was disassembled and the internals replaced.
During subsequent testing, CVCS-1-LCV-460 functioned normally.
Inspection of the removed valve internals revealed deformation of the upper portion the valve plug.
The deformation rendered the valve inoperable following actuator repair, and was postulated by the licensee to have been caused by the excessive closing force applied by the actuator spring after failure of the actuator diaphragm.
Foulin of Auxiliar Seawater ASW Com onent Coolin Water CCW Heat Exchan ers On December 30, 1993, a one-hour non-emergency report was made to the NRC regarding the past operability of the component cooling water/auxiliary seawater heat exchangers.
During a review of an engineering reanalysis of test and sample data, the licensee determined that the ASW/CCW heat exchangers for both units may have had sufficient foulin'g to have precluded the CCW system from meeting its design basis on August 23, 1990.
This condition may also have existed at various dates prior and subsequent to August 23, 1990, until continuous chlorination was fully implemented in the ASW systems in both units in October 1992.
The review of ASW system heat removal capacity had been prompted by the findings documented in NRC Inspection Report Nos.
50-275 and 323/93-36.
NRC review of this issue will be accomplished when the followup and unresolved items in Inspection Report 50-275 and 323/93-36 are addressed.
d.
Re uest for Enforcement Discretion 62703 On December 17, 1993, the licensee initiated troubleshooting activities on a safety-related 125 VAC inverter (IY-22) to determine the cause of two undervoltage transients.
As a result of delays and equipment failures, the licensee was unable to return the inverter to service within the time limit.of the 24-hour Technical Specifica-tion Action Statement, which expired at 5:40 a.m.
on December 18, 1993.
At approximately 4:40 a.m.
on that date, the licensee
requested that the NRC exercise its discretion to not enforce compliance with the required actions of TS 3.8.2.1.,
"Onsite Power Distribution."
The NRC granted an 8-hour extension of the action statement, during which time the licensee successfully repaired and returned the inverter to service.
The NRC noted that enforcement discretion discussions had been initiated with the NRC about one hour before expiration of the action statement, although unexpected problems had occurred with the work more than 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> before the action statement expired.
Also, during the enforcement discretion discussions with NRC management; the licensee did not refer to the most recent guidance for requesting the exercise of enforcement discretion by the NRC.
The license's followup written request, dated December 20, 1993, also lacked appropriate detail in the description of the work and time required to complete the evolution, and did not indicate approval of the request by the Plant Staff Review Committee, although completion of this review and approval was 'stated in the licensee's transmittal letter.
The licensee corrected the inadequacies by issuance of Revision 1 to the submittal, dated December 21, 1993.
In the future, the licensee plans to take more timely actions to contact the NRC if unscheduled delays are encountered with less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> remaining in an action statement, and was planning to conduct training of plant staff personnel on appropriate actions and references associated with requesting enforcement discretion from the NRC.
e.
In this case; the weaknesses noted above had minimal safety significance.
The concerns appeared to have been corrected by the licensee's revised submittal, or will be addressed by the licensee's training and guidelines discussed above.
Unex lained Difference Between Calculated and Actual Estimated Critical Position of Control Rods During the December 31, 1993, restart following the December
turbine/reactor trip, the actual critical position of the control rods was 79 steps less than the calculated estimated critical position (ECP).,
The calculated ECP indicated that criticality would be achieved with Control Bank D withdrawn 150 steps.
Criticality was achieved with Control Bank D at 71 steps.
This difference between actual critical position and the ECP was the largest experienced at Diablo Canyon to date.
This difference, though larger than usual, was within TS 4.1. 1.1.2. limits.
Licensee investigation through the end of this report period had not identified the root cause of the discrepancy.
Licensee and vendor (Westinghouse)
investigation was continuing.
This item will be followed under open item 50-275/93-34-01.
No violations or deviations were identifie.
Maintenance 62703 During the inspection period, the inspectors observed portions of, and reviewed records on, selected maintenance activities to assure compliance with approved procedures, Technical Specifications, and appropriate industry codes and standards.
Furthermore, the inspectors verified that maintenance activities were performed by qualified personnel, in accordance with fire protection and housekeeping controls, and that replacement parts were appropriately certified.
The inspectors observed portions of the following maintenance activities:
Descri tion Dates Performed Rod Control Function Generator Replacement (W/0 C0121629)
Diesel Generator 2-3 Low Precirculation Oil Pressure Investigation (W/0 C0121216)
FCV-22 Indication'Troubleshooting (W/0 C0121458)
ASW Motor Operated Valve (FCV-495)
Troubleshooting (W/0 C0121253)
CCW Heat Exchanger 2-1 Cleaning and Eddy Current Inspection (W/0 C0117232)
Inverter 2-2 Investigation and Repair (W/0 C0118079)
Replace
Y power supply for protection set 2,
steam generator pressure instrument loop, Unit
(W/0 C0121103).
No violations or deviations were identified.
6.
Surveillance 61726 January 5,
1994 December 16, 1993 December 30, 1993 January 6,
1994 January 11, 1994 December 17, 1993 December 15, 1993 The inspectors reviewed a sampling of Technical Specifications (TS)
surveillance tests and verified that:
(1)
a technically adequate procedure existed for performance of the surveillance tests; (2)
the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and (3) test results satisfied acceptance criteria or were properly dispositioned.
The inspectors observed portions of the following surveillance tests on the dates shown:
Procedure Descri tion Dates Performed STP M-9A Diesel Generator 2-3 Routine Surveillance Test December 17, 1993
STP P-6B STP-R7B Turbine Driven Auxiliary Feedwater Pump 1-3 Routine Surveillance Test (Data review)
Determination of Hoderator Tempera-ture Coefficient at Power (Unit 1)
(Data review)
December 22, 1993 January 7,
1994 No violations or deviations were identified.
7.
Observations of Simulator Trainin 41500 On December 22, 1993,* the inspector observed training in.the simulator (Lesson LR935C6) which provided operators with an overview of the new reactor protection system (Eagle 21)
and several of the possible failures which the system may experience.
The operators reviewed various changes in circuit characteristics associated with steam dump operation, steam line break logic, and main steam line isolation., Also, TS changes were reviewed in detail.
Instructors, Instrument and Control engineers, and operators worked as a team during the training session.
This method of
.
instruction appeared appropriate.
Operators participated in detailed discussions and appeared involved in obtaining a thorough understanding of the new protection system, scheduled to be installed during the upcoming Unit 1 outage starting March 12, 1993.
The inspector observed additional licensed operator training in the simulator (Lesson LR935S2)
on January 4,
1994.
The training addressed shift crew performance as a team during shutdown abnormal procedures.
Skills exercised and discussed included understanding of plant equipment configurations and accident responses, individual operators'lant knowledge and diagnostic skills, team communications, and team diagnostic skills.
The observed scenario included multiple equipment malfunctions including failure of residual heat removal (RHR) heat exchanger outlet valve HCV 638, concurrent loss of offsite startup power and loss of emer-gency diesel generators (EDGs) l-l and 1-2, RHR check valve failure, RHR pump failure, and a
KV Bus F differential trip.
This training session was not a graded evaluation and was run in a manner to allow the opera-tors to maximize the training value of the scenario.
This lesson was done at this time in preparation for the upcoming Unit 1 outage.
No violations or deviations were identified.
8.
CCW Tube Frettin 92701 The licensee discovered tube'fretting damage at baffle plate locations in both of the redundant Unit 2 CCW heat exchangers tubes in March, 1993, and documented resolution of the root cause and corrective action in Nonconformance Report (NCR) DC2-93-TS-N017.
The NCR determined the root cause of the fretting to have been flow through the CCW heat exchangers in excess of design limits (18,000 gpm), resulting in tube vibration.
This excess flow was caused by the licensee allowing CCW flow from two RHR heat exchangers to be channeled into one CCW/ASW heat'xchanger during some operating configurations.
The failure to properly implement the CCW system design basis ultimately damaged several 'tubes and required
plugging of 10 tubes in each heat exchanger, resulting in a long-term degradation of heat removal capacity.
"The licensee stated that suffi-cient margin continues to be available to remove design basis heat loads.
The licensee's failure to prevent heat exchanger tube fretting by ensuring operation of the CCW heat exchangers in a manner consistent with the plant's design basis was a violation of 10 CFR 50, Appendix 8, Criterion III, which requires that the design basis'e translated ihto procedures.
Since the criteria of Paragraph VII B(2) of the NRC Enforcement Policy were sati'sfied, this violation is not being cited (NCV 50-323/93-34-02, closed).
Corrective actions documented in the NCR included revision of routine Operations procedures for RHR cooling to preclude operation at high CCW flow.
Permanent revision of the procedures was still pending at the end of this inspection period, although Operations Standing Orders had been implemented as an interim measure to require that design basis flow limits for CCW heat exchangers not be exceeded.
During an unrelated routine review of engineering activities, which occurred before the Plant Staff Review Committee (PSRC) closure of the NCR, the inspector identified that the licensee had not appropriately considered an expected accident-induced failure of a Class II valve operator installed on a safety related valve, with respect to the recently resolved cause of CCW heat exchanger tube fretting.
Additionally, the need to revise emergency procedures and abnormal procedures involving design flow limits for long-term RHR cooling were not indicated in the NCR.
The licensee acknowledged the validity of these concerns, incorporated them into the NCR, and performed additional reviews.
These concerns are discussed further below.
Class II.Valve 0 erator Failure:
The licensee had previously determined that, in the event of a steam line break outside containment or during the recirculation phase after a loss of coolant accident, the CCW outlet valves on both residual heat removal (RHR) heat exchangers (FCV-364 and FCV-365) would be expected to fail open because of the temperature and radiation effects on the Class II valve operators.
This was considered a
failure in the safe direction, and was analyzed and documented as acceptable in engineering calculations performed in 1990.
However, since a single failure could render,a CCW heat exchanger inoperable following a design basis event, the consequences of probable operator actions to direct CCW flow from both RHR heat exchangers into the remaining CCW heat exchanger would result in flow greater than the design basis, and cause additional tube fretting.
Lack of Guidance to 0 erators in Emer enc Procedures:
The NCR did not identify that emergency and abnormal procedures involving RHR cooling may need revision to preclude high flow rates through the CCW heat exchanger.
As noted above, failure of a single CCW heat exchanger may be assumed during a design basis event.
During decay heat removal following an accident or in abnormal operating situations, according to current proce-dure requirements, operators would be allowed to direct CCW flow from both RHR heat exchangers through the single CCW heat exchanger, exceeding design basis flow limits and promoting additional tube frettin The licensee agreed that the above concerns had not been addressed in the NCR but noted that the safety significance was low, since the tube fretting occurred over a long term (days) rather than a short term (seconds or min'utes).
One non-cited violation was identified.
9.
Licensee Event Re ort LER Followu 90712 The inspector performed an in-office review of the following LERs associated with operating events.
Based on the information provided in the report, the inspectors concluded that the licensee had met the reporting requirements, had identified root causes, and had taken appropriate corrective actions.
The following LERs are closed:
93-02, Revision
Containment Isolation Valve Not Isolated in Accordance With l'echnical Specification 3.6.3 Due to Personnel Error 93-06, Revision
93-08, Revision
Unit 2:
Technical Specification 3.3.3. 10 Explosive Gas Effluent Monitoring Action Requirement Violation Due to Personnel Error During the Original Procurement Block Valves Installed in Inlet/Discharge Side of Overpressure Protection Devices Due to Vendor Design Deficiency 92-06, Revision
Anchor Darling Check Valve Bonnet Dowel Pins Not in Compliance with Design Requirements Due to Hanufacturing Error No violations or deviations were identified.
10.
Followu of 0 en Items 92701 a.
Closed Unresolved Item 50-275 92-16-04 CCW Heat Exchan er Heat Removal Ca abilit with Res ect to Heat Exchan er Tube Frettin Concerns The licensee identified that the tube fretting discovered in the Unit 2 CCW heat exchangers was the result of excessive flow through the heat exchanger, as discussed in Paragraph 9 above.
The concern regarding available heat removal capacity was addressed in detail in NRC Inspection Report Nos. 50-275/93-36 and 50-275/93-36, and will be resolved during followup on that inspection report.
Therefore, this item is close b.
Closed Unresolved Item 50-275 91-01-01 Licensee Fire Protection Audit Findin s
A licensee audit in November 1990, identified concerns in several areas of 10 CFR 50, Appendix R.
Additional licensee followup in 1991 identified further concerns.
During followup inspections, the NRC noted that the licensee's effort to identify and correct these concerns appeared aggressive, and that further NRC action would be based on the effectiveness of followup licensee audits, the safety significance of the findings, and the overall aggressiveness of the licensee's actions to identify and correct these findings.
Licensee findings were identified involving circuit separation, Operations procedures, emergency lighting, plant ventilation, materials and procedures for safe shutdown system repairs, and other areas.
The licensee stated that all high-priority actions to separate circuits and provide compensatory measures for othe'r concerns have been completed, and that work is continuing on lower priority concerns.
The inspector verified several of these completed actions, which appeared to have been completed in an appropriate fashion and with appropriate emphasis on priority.
The licensee established formal NRC commitments to complete these efforts and resolve any additional findings within this scope these efforts.
NRC followup action has been performed to assess the safety significance of the licensee's findings.
The significance of most of the findings appears to have been low, with the exception of the inadequate separation of-the EDG carbon dioxide (C02) suppression system actuation switches in both units; the lack of repair materials; and the lack of circuit analysis for em'ergency lighting, ventilation, and communications.
The determination of the safety significance of these issues is ongoing and will be completed in a future report.
Based on licensee commitments, and actions completed to date, followup item 50-275/91-01-01 is closed.
NRC resolution of the safety significance of the inadequate separation of the EDG C02 switches, lack of repair materials, and lack of circuit analysis for the items noted above will be followed by an NRC unresolved item (50-275/93-34-03).
No violations or deviations were identified.
11.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable items, violations, or deviations, An unresolved item addressed during this inspection is discussed in Paragraph 10.b of this repor An exit meeting was conducted on January 12, 1994, with the licensee representatives identified in Paragraph 1.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the materials reviewed by or discussed with the inspectors during this inspectio t~
'I