IR 05000275/1991040
| ML16341G446 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/31/1992 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G445 | List: |
| References | |
| 50-275-91-40, 50-323-91-40, NUDOCS 9202180138 | |
| Download: ML16341G446 (34) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
Report Nos:
50-275/91-40 and 50-323/91-40 Docket Nos:
50-275 and 50-323 License Nos:
Pacific Gas and Electric Company 77 Scale Street, Room 1451 San Francisco, California 94106 Facility Name:
Diablo Canyon Units 1 and
Inspection at:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
November 19 through December 31, 1991 Inspectorss H. Wong, Senior Resident Inspector
~
~
M. Miller, Resident Inspector Approved by:
orri, se, eac or rogec s
ec on ate sgne Ins ection Summar
Ins ection from November 19 throu h December
1991 Re ort Nos.
50-275/91-40 and 50-323/91-40
<<d:
Tt i
p i
i 1d i
i ti f
operations, maintenance and surveillance activities, followup of onsite events, open items, and licensee event reports (LERsj, as well as selected independent inspection activities.
Inspection Procedures 61726, 62703, 71707, 71710, 93702, 90702, 92700, and 92701 were used as guidance during this inspection.
9202180138 920131 PDR ADOCK 05000275 G.
Safet Issues Mana ement S stem SINS Items:
None Results:
General Conclusions on Stren ths and Weaknesses:
Strengths - Control room operators successfully coped with the failure of a speed controller power supply for a main feedwater pump in Unit l.
This resulted in the successful recovery from the feed pump speed controller failure and prevention of a plant trip.
Lessons learned from a previous feedwater pump fai lure assisted in the recovery from this event.
In addition, following the feed pump power supply failure, the licensee was pro-active in investigating the improper installation of a pin in an Agastat relay.
In another instance, the licensee demonstrated good coordination and resolution of a vendor representative's identification of a potential problem with a diesel generator crankshaft vibration damper.
Weaknesses
- The licensee's operability evaluation for deficiencies identified in the implementation of Regulatory Guide 1.97 was found to be weak in some areas.
Factual errors were identified by the NRC resident inspectors and in some cases incomplete corrective actions were found.
Si nificant Safet Matters:
None Summar of Violations and Oeviations:
None 0 en Items Summar
1 new open item, 5 items closed, and 1 item remains open
DETAILS Persons Contacted Pacific Gas and Electric Com an
- G. M.
- J. D.
- W. H.
- M J
B.
W.
D. H.
W. G.
- W. D.
R. P.
- D. A.
- T~
LE H. J.
J. A.
S.
R.
R.
- J J
J.
V.
- R. W.
J.
8.
- T. A.
J.
M.
- G. M.
- p Rueger, Senior Vice President and General Manager Nuclear Power Gener ation Business Unit Townsend, Vice President, Diablo Canyon Operations and Plant Manager, Diablo Canyon Power Plant Fujimoto, Vice President, Nuclear Technical Services Miklush, Manager, Operations Services Angus, Manager, Technical Services Giffin, Manager, Maintenance Services Oatley, Manager, Support Services Crockett, Instrumentation and Controls Director Barkhuff, qua'lity Control Director Powers, Mechanical Maintenance Director Taggart, guality Performance and Assessment Director Grebel, Regulatory Compliance Supervisor Phillips, Electrical Maintenance Director Shoulders, Onsite Project Engineering Group Manager Fridley, Operations Director Gray, Radiation Protection Director Griffin, Senior Engineer, Regulatory Compliance Boots, Chemistry Director Hess, Assistant Onsite Project Engineering Hoch, Manager, Nuclear Safety and Regulatory Affairs Moulia, Assistant to Vice President Diablo Canyon Operations Welsch, Operations and Engineering Training Supervisor Burgess, System Engineering Director Sarafain, Senior Engineer, Onsite Safety Review Group The inspectors interviewed several other licensee employees including shift supervisors, shift foremen (SFM), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, and quality assurance personnel.
- Denotes those attending the exit interview.
0 erational Status of Diablo Can on Units
and
Units 1 and 2 were at 100K power essentially the entire inspection period with the exception of one day {November 23).
During this period Unit 2 reactor power was reduced to 50K for condenser cleanin.
0 erational Safet 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 Operations (LCOs)
as prescribed in the facility Technical Specifications (TS).
Logs, instrumentation, recorder traces, and other operational records were examined to obtain information on plant conditions and to evaluate trends.
This operational information was then evaluated to determine if regulatory requirements were satisfied.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed to the oncoming crew.
During each week, the inspectors toured the accessible areas of the facility to observe the following:
(a)
General plant and equipment conditions (b)
Fire hazards and fire fighting equipment (c)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures (d)
Interiors of electrical and control panels (e)
Plant housekeeping and cleanliness (f)
Engineered safety feature equipment alignment and conditions (g)
Storage of pressurized gas bottles The inspectors talked with operators in the control room and other plant personnel.
The discussions centered on pertinent topics of general plant conditions, procedures, security, training, and other aspects of the work activities.
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 professionals conducted frequent plant tours to observe activities in progress and were aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
ALARA considerations were found to be an integral part of each RWP (Radiation Work Permit).
.The inspector noted that an area of potential internal contamination was posted, but the posting was not always visible.
The Post
0
c ~
Accident Sampling hydrogen monitor cabinet contains piping which.may be contaminated.
The cabinet remained opened for about 3 days during calibration activities and a visible posting was not hung identifying potential contamination in the cabinet.
A permanent sign was posted on the cabinet door, but it was not visible when the door was open for calibration.
The individuals performing the calibration procedure appeared to be aware of the potential for contamination.
A sign was promptly posted by health physics personnel.
The post accident sampling lab is a very low traffic area, postings were already hung on the outside of the cabinet, and this appeared to be an isolated instance based on inspection of other areas in the plant.
Therefore, the safety significance of this finding appeared to be minimal.
Ph sical Securit Security activities were observed for conformance with regulatory requirements; implementation of 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.
4.
Onsite Event Follow-u 93702 a ~
Post-Accident Monitorin Instrumentation Re viator Guide 1.97 During review of their design basis memorandum and follow-up of concerns identified by an NRC inspection, the licensee found that sever al post-accident monitoring indicators did not have complete redundancy along with seismic and environmental qualification as specified in Regulatory Guide 1.97.
The licensee issued operability evaluation 91-13RO dated November 22, 1991, to address the concerns.
The licensee identified deficiencies in four areas.
The NRC inspector's review of this issue found deficiencies in the preparation and implementation of the licensee's operability evaluation.
In addition, the NRC inspector reviewed a licensee evaluation that a steam line break event could cause an inadvertent containment spray actuation.
Re ulator Guide 1.97 Deficiencies 1)
Containment Isolation Valve Position Indication Postage stamp size white lights, mounted in several groups on the main control boards in the control room, are intended to provide prompt information to operators of the position of containment isolation valves.
In the event of a containment isolation signal, Emergency Operating Procedure EP E-0 requires that operators verify that containment isolation valves have travelled to the proper position by observing that the lights are off.
The licensee found that these lights could be
vulnerable to loss of function due to electrical, seismic, and/or environmental design deficiencies.
The licensee stated that the red/green light indication located near each of the valve control switches independently met the separation and redundancy requiremen'ts for post-accident monitoring indication for containment isolation valve position indication.
Because the red/green lights are the most reliable means to verify valve position, changes were made to the emergency procedure EP E-1 to require operators to verify the correct valve position using the red/green lights.
The licensee concluded that changes would be more appropriate for E-1 r ather than E-0 in order not to delay operator actions while progressing through E-0.
The inspector reviewed the procedure changes and found that the procedure changes omitted verification of the containment spray valve position for a Phase B containment isolation and omitted the verification of the containment isolation of the fire water inlet line.
The procedure was revised by the licensee to address these findings.
The licensee stated in a meeting with NRC personnel on Oecember 18, 1991, that the white light system will be upgraded to meet Regulatory Guide 1.97 in refueling outages 1R7 and 2R7 and exceptions will be requested where appropriate.
Accumulator Isolation Valve Position Indication The licensee identified that these valve position switches were not qualified to the post accident environment.
The licensee stated that no automatic or manual action is required to put the valves in their accident position.
These valves have power removed and their position is verified every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The licensee stated that closure of the accumulator isolation valves is postulated only during post-accident recovery and is not critical to the recovery.
Because the accumulator tank level and accumulator tank pressure indications are both fully qualified to the requirements of Regulatory Guide 1.97, the licensee stated that these instruments would be available and the valve position indication would not be necessary.
An exception to Regulatory Guide 1.97 will be requested.
This issue is discussed further in paragraph 8 of this inspection report.
Containment Fan Cooler Unit CFCU Heat Removal Ca abilit n ica
~on The licensee identified that CFCU damper position indication switches do not have the required environmental qualifications.
The licensee considers that the availability of qualified indication for CFCU motor speed and CCW Vital Header A and B
flow rate provide adequate indication of CFCU operatio )
Because each fan cooler is designed with redundant dampers and actuators, the licensee considers that the loss of function of a single damper would riot prevent CFCU function.
Therefore, the licensee considers that no compensatory actions are necessary.
Control Room Ventilation Emer enc Dam er Position Indication The licensee identified two failure modes:
(1)
a single failure of a booster fan or associated damper and (2) failure of damper position indication for several dampers in the event of a loss of offsite power.
The single failure of a fan or damper is described in paragraph 4.b below.
The licensee's compensatory actions for the damper position vulnerability included a night order to operating crews to alert-them to the failure vulnerability and the implementation of a design change to provide a Class 1E power supply to indicating circuits for both units.
The inspector verified completion of compensatory actions and found that a nignt order had been issued regarding the booster fan and associated damper failure; however, a night order had not been issued concerning failure of indicating lights.
Lack of clear information regarding ventilation failure modes in the operability evaluation appeared to have resulted in an unclear description of the possible failures, and failure to implement all the compensatory measures specified in the operability evaluation.
NRC Ins ector Findin s
Com ensator Actions 2)
The inspector identified that licensee compensatory actions were not completely implemented.
The license promptly initiated corrective actions to implement all required compensatory measures, as well as to correct the apparent failure to verify that compensatory measures had been implemented.
The corrective actions included procedure changes to require the sponsor of an operability evaluation to verify compensatory measures and changes to the Document Control distribution/filing procedures.
~Accucac The inspector noted that the operability evaluation, dated November 22, 1991 appeared to contain technical inaccuracies.
Specifically, the operability evaluation stated for CFCU's,
"A single white light indicator will light up if any one of the
dampers fails to obtain the proper position."
In fact, there are five white lights that could indicate damper failures; one white light for each CFCU.
Another instance of confusing information included the indication of control room ventilation status.
The operability evaluation referred to white light
damper position indication for various control room dampers.
This was confusing, in that the only apparent white indication was the white "dot" indication over the ventilation mode selector switches.
The individual damper indications on the main vertical boards in the control room are a salmon color.
The licensee agreed to address these inconsistencies in a
revision of the operability evaluation.
3)
~0i Ch Control room operators were initially unsure if CFCU damper indication was necessary because they had received training on a
CFCU design change which welded dampers in a fixed position and therefore made damper movement unnecessary.
Further discussion by operators identified that the change had not yet been implemented.
The licensee has identified that feedback to training is not always formal when a design change is cancelled.
Action Request AO 254281 was initiated to request and track improvement of the process by which operations training is informed, when the schedule for an approved design change is changed.
Steam Line Break Associated with the issues related to Regulatory Guide 1.97, the licensee previously identified the potential for inadvertent artuation of containment spray during a main steam line break in certain areas of the auxiliary building.
Since the narrow range containment pressure transmitters are not qualified for elevated temperatures following a steam break, they could fail high and
'ctuate containment spray.
While operators have demonstrated that they could deal satisfactorily with this scenario, the inadvertent spray adds a complicating circumstance to the steam line break event.
The inspector discussed this scenario with licensee management.
In the exit meeting licensee management stated that a
design change would be implemented to eliminate the unintended containment spray actuation, but they would need some time to develop a schedule.
Licensee management stated that a schedule would be provided by early February 1992.
The licensee stated that a design change would not be in time for the upcoming Unit 1 refueling outage starting in the fall of 1992.
These actions appeared appropriate.
b.
Control Room Ventilation S stem Outside Oesi n Bases On November 21, 1991, the licensee concluded that during a design bases accident, a single failure of a booster fan or its associated damper in the control room ventilation system could result in unfiltered air entering the control room.
This could lead to radiation exposures to control room personnel exceeding the limits of General Oesign Criterion 19 (GOC 19) of 10 CFR Part 50, Appendix A.
While there are two booster fans for each unit, the failure of a fan or its damper is not annunciated nor is the redundant fan started automatically.
When this potential event was identified, a
one-hour, non-emergency report was provided to the NR e
The potential for unfiltered air to enter the control room is caused when a control room ventilation system booster fan fails to start or its associated damper fails to open when the control room ventilation system goes to the pressurization mode of operation.
Outside air is intended to be drawn through the control room ventilation filtration units, but if a booster fan or damper fails the outside air would enter the control room through ducting designed to recirculate control room air.
Control room personnel would not be aware of the entry of unfiltered air other than by an area radiation monitor in the control room.
This monitor is design class II, but provided with class lE power.
The licensee's preliminary calculations indicate that under a 'postulated design bases accident the control room radiation monitor would alarm in 23 minutes.
Without operator actions
.the thyroid dose limits of GDC 19 for the 30-day duration of a postulated accident would be exceeded in approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />.
The licensee's corrective actions included the issuance of a night order describing the potential event, a change to emergency operating procedures to include actions in the event of a booster fan or damper failure, and the installation of streamers on the control room ventilation registers to indicate the direction of air flow.
A design change is being evaluated for long term resolution of the problem.
The NRC inspector reviewed the licensee's immediate corrective actions which appeared appropriate to address the issue.
This issue is described in Nonconformance Report NCR OCO-91-EN-N028 and Licensee Event Report 50-275/83-039-00.
The LER will be reviewed in a subsequent inspection.
Hi h Com onent Coolin Water CCW Tem erature Ourin Post-Accident Rec rcu at>on The licensee identified that, in the recirculation mode after a loss of coolant accident (LOCA), the unavailability of a CCW heat exchanger or ASW pump could result in exceeding design temperature limits in the CCW system.
One of the root causes of this vulnerability was the original plant design assumption that the worst case failure during the LOCA was loss of an entire ECCS train electrical bus.
Analyses failed to consider that on loss of one ASW pump or one CCW heat exchanger, heat loads from all five containment fan cooler units (CFCUs)
and both residual heat removal (RHR) heat exchangers would be dealt with by one train of CCW, raising CCW temperature above the 120 degrees F design limit.
In Operability Evaluation 91-15RO the licensee described compensatory changes to the Emergency Operating Procedure EP E-1.3, which directs the control room operators to shut down one train of RHR and allow only three CFCUs to be in operation if only one CCW heat exchanger was available.
The licensee stated this would ensure CCW temperature limits of pumps cooled by CCW would not be exceeded.
The licensee determined that this potential event was outside the plant design basis and therefore reportable to the NRC.
In addition, the licensee plans to have the vendor (Westinghouse)
conduct a more detailed analyse.
The inspector reviewed the licensee's operability evaluation and implementation of associated compensatory actions.
The licensee is preparing a
LER on this topic which will be reviewed in a future inspection.
Safet In 'ection and Centrifu al Char in Pum Runout Durin Post-LOCA Recirculation On October 1, 1991, Westinghouse issued a letter which described the potential vulnerability for safety injection (SI)
pumps and centrifugal charging pumps (CCPs) to experience runout.
The licensee determined that this may occur after a LOCA, when hot leg recirculation is initiated.
At that time, the suction of the SI pumps and CCPs would have switched from the refueling water storage tank, to the discharge of the residual heat removal (RHR) pumps, which is an increase in suction pressure of about 125 psig.
This higher suction pressure could allow the SI pumps and CCPs to experience runout conditions if reactor coolant system pressures and pipe friction losses were sufficiently low.
The licensee's evaluation in Operability Evaluation 91-14RO stated that piping configurations of Unit 2 would provide enough back pressure to prevent runout conditions.
However, Unit 1 SI pumps and CCP l-l were vulnerable to runout.
Startup test data showed that, in recirculation lineup, the SI pumps and CCP l-l had run above runout limits.
Westinghouse and the pump vendor reviewed the test data and determined that, based on acceptable vibration levels, the pumps were operable during recirculation without any restriction.
The inspector identified four questions which the licensee is currently evaluating.
First, what is the safety significance of degraded voltage conditions while pumps are operating above runout'econd, since the pump performance at runout conditions was obtained only at the time of startup, how is the licensee assured that pump performance at runout conditions continues to be satisfactory7 Third, what are the effects of operation above runout on the motors And fourth, are the Technical Specifications applicable to the piggyback mode of operation7 The resolution of these concerns will be followed as open item
'50-275/91-40-01.
Failure of a Hain Feedwater Pum
- Unit 1 On December 3,
1991, the speed controller for Unit 1 main feedwater pump 1-1 failed as a result of a power supply failure.. The operators promptly took manual control of the pump and averted a plant trip.
The successful recovery from this failure was partially due to operations management effective communication of lessons learned from a feedwater pump trip which occurred earlier in the year and did result in a plant trip.
Operators were aware of the lessons learned and applied them during the even The failure of the power supply should not have resulted in speed controller failure because the controller was designed to automatically switch to a redundant power. supply upon failure.
During the investigation of the main feedwater pump speed controller failure, the licensee found two Agastat relays which had been assembled incorrectly, although it was not apparent that the incorrect assembly caused the failure of the feedwater pump speed controller.
The operating pin, which actuates an instantaneous auxiliary contact, had been inserted so the head of the pin was outside the relay case rather than inside.
Therefore, the point of the pin would not reliably contact the operating mechanism in the relay.
The licensee also confirmed that the relays were wired incorrectly and is in the process of testing to determine the root cause of the speed controller failure.
As corrective action for the generic failure vulnerability of the relays, the licensee plans to take the following steps:
o Include verification of correct positioning of the pin in about 20 percent of the Agastat relays installed in the plant.
Half of those inspected will be in safety-related applications.
o Submit an industry notification via INPO network of the potential for incorrect positioning of the pin.
o Change applicable maintenance procedures to more clearly show correct pin installation.
o Inspect a11 relays in warehouse stock.
o Include verification of correct pin installation as a critical characteristic in receipt inspection of these relays.
o Procure relays with the pin already installed by the supplier rather than as a separate unit requiring installation of the pin ~
These actions appear to be appropriate in response to this equipment failure.
f.
Diesel Generator 1-3 Crankshaft Vibration Dam er Concerns
- Unit
On December 18, l991, during the performance of preventative maintenance, the diesel generator vendor representative identified that the crankshaft torsional vibration damper on diesel generator 1-3 was noted to be stiff, rather than free to move, indicating possible degradation of its damping function.
The damper uses engine lube oil and a ring/spider arrangement which internally ports the oil to dampen torsional vibrations of the crankshaft.
Lockup of the damper could cause fatigue of the crankshaf (
The damper was flushed with diesel fuel oi-l and then with engine lube oil, and freedom of movement was restored.
As oil in the damper can cause stiff movement, vendor representatives stated that indication of proper damper function depends on the degree of stiffness exhibited by the damper, the amount of time for engine oil to drain from the damper, and whether oil can be observed to flow through the drain passages.
Flushing did produce a small amount of sludge.
The damper had not been cleaned or flushed since initial operation of the diesel generator.
Vendor representatives and licensee personnel concluded that, in the as-found condition of the damper, the diesel generator was capable of performing its intended function.
Previous inspection for freedom of movement of the dampers had occurred for all three Unit 1 diesel generators in February 1991 and for both Unit 2 diesel generators in October 1991.
The NRC inspectors reviewed the licensee's evaluation of the issue (Operability Evaluation 91-16RO)
dated December 16, 1991, attended meetings discussing the issue, observed preparations for the damper flushes, and observed the as-left condition of the damper.
The inspectors noted that no specific safety precautions in the use of solvents were stated in the work documents, and discussed with licensee personnel the need to properly consider personnel and equipment safety when flammable or explosive solvents were being considered.
The licensee subsequently chose to use fuel oil or lube oil for flushing rather than solvents.
This corrective action appeared to be appropriate.
The licensee is evaluating the frequency for performing flushes or other cleaning of the damper.
No violations or deviations were identified.
5.
Maintenance 62703 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 maintenance activities were performed by qualified personnel, in accordance with fire protection and housekeeping controls, and replacement parts were appropriately certified.
o Work Order C0095134-EDG 1-3 Correct Crankshaft Vibration Damper o
Work Order C0094497 -
SSPS MUX Card Data No violations or deviations were identified.
6.
Surveillance 61726 By direct observation and record review of selected surveillance testing the inspectors assured compliance with TS requirements and plant procedures.
The inspectors verified that test equipment was calibrated, and acceptance criteria were met or appropriately dispositione Failure of Steam Admission Valve FCV-95 to Auxiliar Feedwater Terr Tur ine to 0 en - Unit On December 24, 1991, during monthly surveillance testing of the turbine-driven auxiliary feedwater pump, the steam admission valve (FCV-95) failed to open.
This valve has a history of not opening under a variety of operating conditions ( Inspection Reports 50-275/91-27 and 91-38).
This latest failure is more significant than past failures in that this failure occurred with upstream isolation valves open which is the condition in which FCV-95 would be expected to respond during accident conditions.
The surveillance test (STP P-68)
was a cold start of the auxiliary feedwater pump and required only the opening of FCV-95 from the control room.
As a result of the past problems with the valve, the licensee had installed additional monitoring sensors on the valve and associated piping to further investigate the cause of the valve failing to open.
The data from the valve failure was recorded by the instrumentation.
Preliminary licensee evaluation did not reveal a
root cause for the failure.
The evaluation determined that the force required to open the valve was approximately 16,000 pounds of stem thrust.
The valve operator was capable of only 14,000 pounds of thrust.
The licensee declared the valve inoperable and changed operator gearing to raise the available thrust to approximately 22,000 pounds.
The motor was also replaced to assure that there was no degradation of the motor caused by the failure of the valve to open.
In addition, a hole was drilled in the upstream face of the valve to eliminate the potential for trapping pressurization between the valve disks.
However, the latest failure occurred with steam pressure maintained to FCV-95 which does not support the licensee's theory that pressure trapped between the disks caused the valve to fail.
Pressure was not thought to be trapped between the valve disks if steam was maintined to the valve.
After the valve modifications were completed, FCV-95 was retested, the required opening thrust was found to be approximately 8000 pounds, and the valve was declared operable on December 25, 1991.
The licensee revised the existing Operability Evaluation 91-07 (Revision 2, dated January 2, 1992) to reflect the latest failure.
The NRC inspectors reviewed the revised Operability Evaluation and witnessed valve testing conducted before and after the failure on December 24, 1991.
The revised Operability Evaluation stated that weekly testing would continue to further investigate the cause of the valve failure.
The inspector noted that weekly testing would be with the upstream steam isolation valves (FCV-37 and 38) closed which would result in less than full system pressure to FCV-95.
Consequently, this may not assure that FCV-95 would continue to maintain its operability.
This point was discussed with engineering and maintenance management.
The licensee is evaluating ways to conduct the test to assure operability and determine the cause of the valve failure.
Licen'see management stated that the same valve
in Unit 2 would be instrumented to evaluate any differences in valve behavior.
The inspector wi 11 continue to monitor the testing of FCV-95 and the licensee's investigation of the root cause of failure in future inspections.
No violations or deviations were identified.
En ineerin Safet Feature Verification 71710 Portions of the post-accident monitoring, safety injection and fuel handling building ventilation systems were inspected to verify system configuration, equipment condition, valve and electrical lineups and local breaker positions.
No violations or deviations were identified.
Environmental gualification of Safet In ection Accumulator Valves 9270 Emergency Operating Procedure EP E-1 specifies that when safety injection accumulator pressure has been reduced to less than 200 psig the accumulator outlet isolation valves (8808 A-D) should be closed.
If the outlet valves cannot be closed, the procedure specifies that the. nitrogen fill valve (8880)
be closed and the accumulator vent valves (8875 A-D) on the affected accumulators be opened along with the nitrogen vent control valve (HCV-943) to vent the nitrogen in the accumulators.
However, the safety.injection accumulator discharge isolation valves (8808 A-D) and accumulator vent valves (8875 A-D) are not environmentally qualified for the post-LOCA containment environment.
The NRC inspector questioned licensee personnel on the safety significance of the failure to isolate the accumulators during and after a LOCA, particularly regarding the potential for adversely affecting core cooling if nitrogen were to be injected into the reactor coolant system.
The licensee provided a discussion of their evaluation and conclusion that the potential nitrogen injection was not a safety concern.
This is based on the fact that, for large break LOCAs, the nitrogen is postulated to go out the break and that core decay heat is removed through the water going out the break location.
For breaks in piping less than 8 inches in diameter, Westinghouse small break LOCA analyses described in WCAP 9600, dated June 1979, states in Section 2.9 that depending on pipe break size, stable conditions are either reached above accumulator injection pressure or before the accumulators empty of water.
After the issue was raised by the inspectors the licensee contacted Westinghouse representatives who stated that plant cooldown in accident conditions is accomplished by the RHR system, which would be drawing suction from the refueling water storage tank or containment recirculation sump, and therefore would not be adversely affected by any nitrogen injection into the reactor coolant system.
Venting of non-condensible gases could be accomplished through the reactor vessel head vent valves which are environmentally qualified for post-LOCA operatio The inspector had no further questions regarding the evaluation at this time.
The evaluation appears to support the licensee's conclusion that the accumulator isolation and ven't valves do not need to be environmentally qual ified.
No violations or deviations were identified.
9.
Licensee Event Re ort Follow-u 92700)
LER 50-275/91-003-00:
Loss of Residual Heat Removal RHR Flow
)
Whs e
Fs in Refue sn Cavst and Late 50.
2 Re ort to NRC C osed This LER involved a trip of an operating RHR pump while filling the refueling cavity from the refueling water storage tank.
This was caused by an inadequate shift turnover which failed to communicate the status of procedure completion and which steps remained to be performed.
The cause of the late report to the NRC was shift management failure to recognize that the loss of RHR when RHR is required to be in operation was required to be reported in accordance with procedure AP C-11S2, Attachment 5.1.
The licensee's corrective actions were to issue:
an operations incident summary regarding the event, a memorandum to operations personnel regarding prompt notification of events, an Operations Department Policy to require the completion of procedural steps to be clearly indicated, and procedural changes to disable the RHR pump trips following entry into Mode 5.
The inspector reviewed the event and the licensee's corrective actions.
The licensee's actions appeared appropriate.
This closes LER 50-275/91-003-00.
b.
LER 50-275/91-012-00:
Emer enc Diesel Fuel Oil Inventor Missed urves ance ose This LER involved the failure to perform a required surveillance for the diesel fuel oil inventory within the time specified by Technical Specifications.
The event was caused by the failure of personnel to review appropriate status reports.
The licensee's corrective actions were to perform the surveillance (which was satisfactory),
review documents for other possible overdue surveillances, advise test coordinators of the event and the proper use of surveillance tracking reports to determine testing status, and the enhancement of the tracking system to highlight surveillances that are due.
While the system enhancement is still in progress, the licensee's actions appear appropriate to prevent further recurrence.
The inspector reviewed the current surveillance testing report and noted no instances of overdue Technical Specification surveillance tests and that test coordination personnel were knowledgeable of tests coming due.
This event appears to be an isolated instance.
This closes LER 50-275/91-012-00.
No violations or deviations were identifie ~
~
10.
Open Item Follow-up 92703, 92702 a.
Unresolved Item 50-275/90-30'-03 Closed LER 50-275/89-019-01 ose Unreso ve tern
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ue Han in Bui ldin Ventilation Issues These items discuss the fuel handling building ventilation system and failures to maintain a 1/8 inch water differential pressure.
The licensee has continued to review various corrective actions and has not initiated an integrated plan to correct continuing fuel handling building ventilation system inoperability.
At this time, both fuel handling building ventilation systems remain inoperable, when a supply and exhaust fan are operated together in the normal ventilation mode.
Movements in the spent fuel pool require turning off the supply fan.
This item will remain open pending licensee resolution of fuel handling building ventilation problems.
b.
Followu Item 50-275/91-03-03:
Intake Structure Deterioratin Material Condition Closed This item involved an NRC inspector's observations of some degrading material conditions at the intake structure.
The licensee is tracking the completion of specific actions.to upgrade equipment in Action Plan 3450.04/001 and NCR DCO-91-EN-026.
Those actions focus on the prevention of water inleakage into the intake structure and also the correction of degradation caused by the previous inleakage.
Completed actions include the installation of some of the replacement hatches on the top deck of the intake structure, replacement of a
corroded electric panel for Unit 2, replacement of corroded piping spools, installation of splash guards on pumps, investigation of concrete quality, repair of deficient concrete surfaces, and repair of intake cooler leaks.
Weekly meetings are conducted, which include maintenance and engineering personnel, to review the status of actions related to the intake structure and to highlight any new issues of concern.
AR's are used to document any deficient conditions which are identified.
In addition, a recurring task work order (R0094822) is used to perform a semiannual inspection of the intake structure.
This inspection includes personnel from the various departments, such as operations, maintenance, gC, security, and engineering.
The inspector reviewed the license's corrective actions and verified conditions at the intake structure, including observations shortly after a rain storm.
Based on these observations and discussions with NRC and licensee personnel, it appears that the material condition of the intake structure has greatly improved and licensee management has supported maintenance and upgrades of equipment.
This closes Followup Item 50-275/91-03-03.
The material condition of the intake structure will continue to be reviewed in the routine inspection program.
No violations or deviations were identifie ll.
Exit 30703 On January 9, 1992, an exit meeting was conducted with the licensee's representatives identified in paragraph 1.
The inspectors summarized the scope and findings of the inspection as described in this report.