IR 05000275/1987044
| ML16342B413 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/17/1988 |
| From: | Johnston K, Mendonca M, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E558 | List: |
| References | |
| 50-275-87-44, 50-323-87-45, NUDOCS 8803080119 | |
| Download: ML16342B413 (28) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
License Nos:
Licensee:
50-275/87-44 and 50-323/87-45 50-275 and 50-323 DPR-80 and DPR-82 Pacific Gas and Electric Company 77 Beale 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:
December 20, 1987 through January 30, 1988 Inspectors:
L.
M. Padovan, Acting Senior Residen Inspector 2. iT gb Date Signed Approved by:
K.
E. Johnston, Resident Inspecto M.
M. Mendonca, Chief, Reactor Projects Section
Date Signed lag() b Date Signed Summary:
Ins ection from December
1987 throu h Januar
1988 Re ort Nos.
50-275/87-44 and 50-323/87-45 Areas Ins ected:
The inspection included routine inspections of plant operations, maintenance and surveillance activities, follow-up of onsite events, open items, radiological controls, physical security, licensee event reports (LERs),
and enforcement item follow-up, as well as selected independent inspection activities.
Inspection Procedures 25026, 30702, 30703, 41400, 50095, 60710, 61710, 61726, 62703, 71707, 71708, 71709, 71881, 90712, 92700, 92701, 92702, 93702, and 94703 were applied during this inspection.
Results of Ins ection:
One violation concerning plant security was identified.
Inspector perceptions regarding root cause analysis and corrective action, configuration control, and plant staff assessments of first-of-a-kind plant evolutions are included.
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DETAILS Persons Contacted
~J.
D. Townsend, Acting Plant Manager J.
A. Sexton, Assistant Plant Manager, Plant Superintendent
- J.
M. Gisclon, Acting Assistant Plant Manager for Support Services
- C.
L. Eldridge, guality Control Manager
"T. A. Bennett, Acting Maintenance Manager
"S.
G. Banton, Engineering Manager R.
G. Todaro, Security Supervisor
"D. B. Miklush, Unit 2 Outage Manager
~M.
E.
Leppke, Onsite Project Engineer
- M. J.
Angus, Work Planning Manager
- W. G. Crockett, Instrumentation and Control Maintenance Manager J.
V. Boots, Chemistry and Radiation Protection Manager L.
F.
Womack, Operations Manager
~T.
L. Grebel, Regulatory Compliance Supervisor
~S.
R. Fridley, Senior Operations Supervisor
"R.
S. Weinberg, News Service Representative
"M.
W. Stephens, I8C General Maintenance Foreman The inspectors interviewed several other licensee employees including shift foreman (SFM), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assurance personnel and general construction/startup personnel.
"Denotes those attending the exit interview.
0 erational Safet Verification a.
0 erational Status and General 0 er ati onal Status of Diablo Can on Units 1 and
During the reporting period of December 20, 1987 through January 30, 1988, Diablo Canyon Unit 2 was at 100K power and Unit 1 initiated a coast down into its second refueling outage scheduled for March 1988.
Spent fuel pool reracking was completed on Unit 1 with drag testing continuing on through February.
Events during the report are discussed later in this report.
A brief description of events and significant occurrences follows:
On December 30, both trains of the Unit 1 Auxiliary Building ventilation system became inoperable as a
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of deficient equipment clearance (Section 4b)
~
On January 8, 1988, Unit 1 tripped from 100Fo power when a plant technician inadvertantly caused simulated reactor coolant system loop low flow signal (Section 4a).
On January 27, 1988, an Unusual Event was declared as a result of smoke emanating from the high pressure turbine of the main turbine generator (Section 4c).
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 trends were reviewed for compliance with regulatory requirements.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed.
During each week, the inspectors toured the accessible areas of the facility to observe the following:
(1)
General plant and equipment conditions.
(2)
fire hazards and fire fighting equipment.
(3)
Radiation protection controls.
(4)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures.
(5)
Interiors of electrical and control panels.
(6)
Implementation of selected portions of the licensee's physical security plan.
(7)
Plant housekeeping and cleanliness.
(8)
Essential safety feature equipment alignment and conditions.
(9)
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 involved work activities.
Main Steam Line Noise As a result of renewed operations department concern about Unit 2 Main Steam Isolation Valve (MSIV)
noise, during the week of January 25, the licensee established a task force involving site engineering, Onsite Project Engineering Group (OPEG),
and the PG8E Division of Engineering Research (DER).
At the end of this inspection report period, the task force had established an action plan and had initiated vibration analysis of the Unit 2 main steam lines.
Other planned actions include a visit by the MSIV
manufacturer's representative, obtaining written qualitative assessment from operations and engineering personnel previously involved, and reviewing MSIV maintenance history.
Following this data collection effort the licensee anticipates having the noise source pinpointed so that prescribe further corrective actions and inspection scope can be prescribed.
The proposed actions appear to be prudent.
However, concern of the MSIV noise first surfaced in January 1987.
At the end of the current report period, it was unclear why it has taken a year to establish a comprehensive program to identify the source of the noise.
The inspector will followup the results of the MSIV noise task force and review the adequacy of previous efforts to identify the noise during routine inspection.
C.
Perr Station Unex ected 0 enin of Main Steam Isolation Valves NRC Preliminary Notification PNO-III-88-05 described unexpected opening of MSIVs upon deenergization of reactor protection system bus B.
Though Perry is a boiling water reactor, the inspector requested the licensee to investigate the possibility of that situation occurring at Diablo Canyon.
The licensee concluded that the identified unanticipated MSIV opening would not occur, due to power supply separation and method of wiring MSIV solenoid valves (energize to vent).
No violations or deviations were identified.
3.
Onsite Event Follow-u a ~
Unit 1 Reactor Tri Due to Simulated RCS Loo Low Flow On January 8, 1988, at 1011 a.m., with the unit at 100 percent power, a reactor trip and subsequent turbine trip occurred due to a simulated reactor coolant system loop low flow signal.
All automatic safety systems responded as required, and the unit was stabilized in Mode 3.
A plant technician was refilling the sensing line from a reactor coolant loop 3 transmitter when he inadvertently depressurized the common high side pressure leg at a rate sufficient to produce a low reactor coolant flow signal on two out of three loop 3 flow channels.
With the plant operating above 35% reactor power (permissive P-8), the required reactor trip logic was produced.
From discussions with the plant technician, the inspector ascertained the technician was reinstating the reactor coolant flow channel to service in accordance with STP I-8B5.
The procedure specified several alternate ways to backfill the flow transmitter, sensing line, and instrument manifold.
Additionally, the procedure indicated the instrument supervisor would decide the manner in which the system was to be backfilled.'
Previously, on several occasions, RCS flow transmitters had been replaced, with the plant at power, utilizing back filling from a primary water source.
In a briefing with the I&C technician, the instrument supervisor and technician agreed to refill the transmitter sensing lines by filling from the RCS rather than by backfilling with a primary water source.
This methodology was chosen to ensure that any particles remaining in the tubing from corrective maintenance just performed on the sensing line would be flushed out of the lines.
However, when filling and flushing the sensing lines through an instrument drain valve, the technician depressurized the common leg of the flow transmitters at a rate sufficient to cause a simulated RCS loop low flow rate reactor trip.
The inspector concluded the technician was unaware that the valve manipulation could create a sufficient perturbation in sensed flow to cause a reactor trip.
Additionally, the inspector determined the reinstatement procedure did not specifically provide for filling the sensing lines by flushing RCS water through the instrument drain valve; since the STP was vague in permitting the instrument supervisor to decide the manner in which the system was to be backfilled.
Since this filling evolution was of a type not previously used on the transmitters, the inspector concluded that the technician and supervisor should have stopped and obtained further guidance from higher level supervision or management.
In discussing this concern with plant management, the inspector emphasized that when performing any unusual activity, a special level of attention is required, especially if the activity is different from that previously performed (flushing vs. backfilling).
Licensee management agreed that (1) latitude to vary from the procedure would be removed, (2) precautions would be added to the procedure, and (3) management would re-emphasize to technicians and supervisors that upon reaching options or excess latitude in a procedure, the activity should stop and guidance should be obtained.
Other STPs involving transmitters that share a common tap are to be reviewed and revised, as appropriate.
Additional information on this event is provided in LER 50-275/88-02.
As discussed in PG8E letter No.
DCL-87-136 dated June 15, 1987, several previous events have been. identified as "instances of
~ noncompliance with procedures, or of failure to limit actions within the defined scope and intent of procedures."
Corrective actions to remedy this situation were specified.
This event further demonstrates that licensee corrective actions to date have not been fully effective.
Additional management attention to implement corrective actions in this regard is deemed appropriate.
Auxiliar Buildin Ventilation S stem Ino erable On December 30, 1987, at 1:23 p.m., with Unit 1 at 93 percent power, both trains of the auxiliary building ventilation system were
declared inoperable, resulting in an entry into Technical Specification (TS) 3.0.3.
As described in Licensee Event Report 50-275/87-028, dated January 29, 1988, auxiliary building exhaust fan E-2 was cleared to support maintenance on the ventilation system.
The alternate fan, E-l, tripped on thermal overload when a
clearance deficiency resulted in dampers repositioning, impairing the flow path of the fan.
Fan E-1 was 'restarted at 1:38 p.m.
The adequacy of the licensee's review of this event wi 11 be the subject of a follow-up inspection.
C.
S ent Fuel Pool (SFP Leaka e
The presence of water has been detected in leakoff lines at the sumps of both Unit 1 and Unit 2 SFPs.
The Unit 1 and Unit 2 SFP leakage detection systems are designed to detect leakage of pool water past the stainless steel liners.
A SFP is divided into six areas, each having a leakoff line with a manual isolation valve on each line located at the SFP sump.
Each valve can then be individually opened to measure the accumulated leakage from a general liner area.
From September l7, 1987, to January 30, 1988, the accumulated leakage from several Unit 2 SFP leakoff lines was about 96 liters.
Chemical and radiological analysis indicated the accumulated water was SFP water, confirming a leaking Unit 2 SFP liner.
Licensee investigative measures are described later.
Regarding the Unit 1 SFP, water has been detected in only one leakoff line (valve 1-56).
Since January 30, 1988, 5.5 liters were collected in the leakoff line with the majority of the liquid having been collected on January 20 and 21, 1988.
By January 29, 1988, the amount of water present in the leakoff line was zero.
According to the licensee, radiological analysis (content of tritium, Co-58, Co-60, and Cs-137)
and chemical content (boron, PH, and chloride) of the accumulated water confirmed the water was not SFP water and thus the Unit 1 SFP liner was not leaking.
The, Unit 1 SFP does contain spent fuel.
In order to identify the location of liner leakage on the Unit 2 pool and to identify the source of water that appeared in the Unit 1 SFP leakage detection system, the licensee formed a Spent Fuel Pool Leak Task Force and developed an action plan for the investigations.
Representatives from plant management, Chemistry and Radiological Protection, Construction, Engineering and Construction Coordination were assigned to the task force.
Regular meetings to discuss information obtained and plan future courses of action were held.
The inspectors will follow the licensee's evaluations and corrective actions in this regard.
d.
Smolderin Insulation on the Unit 1 Hi h Pressure Turbine On January 27, 1988, with the plant at 90 percent power, the licensee declared an Unusual Event as a result of smoke emanating from a small section of oil soaked insulation on the high pressure
turbine of the main turbine generator.
The fire brigade was dispatched, and as a precautionary measure, the licensee requested
.
the backup assistance of the California Department of Forestry.
After removing most of the affected insulation from the high pressure turbine area, the smoldering diminished, and the Unusual Event was terminated.
Maintenance personnel inspected the high pressure turbine area and removed insulation suspected of being oil impregnated.
The source of the oil leak was investigated by licensee and turbine manufacturer personnel, but no leakage of lubricating oil was identified.
Accordingly, the licensee developed an Action Plan to investigate the source of the lubricating oil.
The resident will follow the licensee's evaluation and corrective actions.
No violations or deviations were identified.
4.
Maintenance 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.
a.
Diesel Generator 1-3 Maintenance Outa e
The inspector observed portions of a number of maintenance activities performed on Diesel Generator (DG) 1-3, the swing diesel generator.
The activities were performed in conjunction with the first of four scheduled DG 1-3 outages.
The staggered outages will be performed in lieu of a longer outage when Unit 1 is in its refueling outage since, unlike DGs l-l and 1-2, DG 1-3 is required to be operable to supply Unit 2 loads.
The maintenance activities witnessed included testing of diesel generator auxiliary relays, replacement of degraded switches, preventive maintenance on the generator space heater, jacket water heater, and lube oil heater, and replacing bus screws.
The inspector noted that all applicable procedures and work orders were being followed.
In addition, the inspector observed that all lifted leads were logged, replacement parts used were properly controlled, instrumentation was calibrated, and Quality Control (QC) was involved in a number of jobs.
No findings were identified.
b.
Unit 2 Control Rod Drive Motor-Generator Set On December 30, 1987, operators noted that vibration on the 2-2 control rod drive motor generator (M-G) set was. two to five times higher than vibration on the 2-1 M-G and requested that maintenance engineering investigate the discrepancy.
The control rod M-G sets supply non-vital rod control powe The inspector observed the maintenance performed on the M-G.
This included removing the M-G, disassembly, cleaning, inspection of the motor and generator bearing, and balancing and meggering of various components.
All'aintenance activities observed were performed using the appropriate controls and procedures.
The electricians appeared qualified to perform the activities.
The high vibration was attributed to, a number of the M-G components being slightly out of balance.
Following reassembly, the M-G was tested at full load in the cold machine shop.
Unit 2 Batter Char er 232 Out ut Breaker The inspector observed portions of maintenance performed on Unit 2 battery charger 232 output breaker 72-2301.
On December 30, 1987, while walking the control boards, a control operator observed that vital battery 23 was discharging
amps at 122 volts while the output of battery charger 232 was zero amps at 132 volts.
Instrumentation on the control board indicated the output breaker (72-2301) associated with battery charger 232 was closed and the redundant battery charger 231 breaker was open.
Additionally, the control room alarm that indicates when no battery charger is aligned to the vital DC bus was not lit.
The control operator dispatched two crew members, including the senior control operator, to the battery charger to investigate the reasons for the battery discharging.
Breaker 72-2301 was found in what appeared to be th'e closed position.
They. opened the breaker and received a "good snap" indicating to them that the breaker had been closed.
They reclosed the breaker and the battery charger 232 amps dipped slightly below zero and reset.
The shift foreman had the breaker reopened, and battery charger 231 was then put in service.
When its associated output breaker was closed onto the bus, its ammeter also took a slight dip, paused at zero amps and then recovered load.
The shift foreman declared battery charger 232 inoperable and entered Action C of TS 3.8.2. 1 which required the charger to be placed back in service within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
Electrical maintenance personnel first inspected the breaker and battery charger in the field, and then suspecting a faulty breaker mechanism, had the breaker removed for bench testing.
The inspector witnessed portions of the bench testing which consisted of testing the breaker overcurrent protection devices.
The electricians had attempted to determine the cause of the battery discharge through operation and inspection of the breaker.
However, the breaker functioned acceptably.
Dur)ng the breaker inspection, two small pieces of insulation were found in the area of the arch chutes.
The licensee determined that the pieces could not have been responsible for the breaker problems since they were too small to interrupt all three spring loaded feet of each contact.
It was also determined that they could not have affected the breaker action or the alarm feature.
The electrical
maintenance department was unable to reproduce the conditions which had existed on December 30.
They inspected all breaker alarm contacts and performed a functional test on the battery charger.
Breaker 72-2301 was replaced with a spare.
The electrical maintenance general foreman stated in the quality evaluation (gE) that the cause could not be determined and that the corrective action to prevent recur rence was to replace the breaker to eliminate the possibility of, an intermittent failure within the original breaker.
The inspector discussed the gE with the general foreman and determined that he had not discussed the event with the operators involved.
The inspector concluded this could be an avenue for the discovery of root cause and discussed with licensee management the need to explore all possible avenues before concluding an investigation.
This item will be followed up under our evaluations of the licensee's root cause and corrective action efforts (see section 9 of this report).
No vi'olations or deviations were identified.
Surveillance 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 dispositioned.
a.
Com onent'oolin Water Pum 1-2 Surveillance Test Procedure (STP)
P-BB, "Routine Surveillance Test of Component Cooling Water Pump,"
was performed to test Unit 1 CCW pump 1-2 and its discharge check valve.
Data was obtained on pump suction and discharge pressure and flow to ascertain pump operability.
Additional data such as vibration readings, temperatures and motor current were also obtained.
The inspector independently reviewed the data taken against the acceptance criteria provided in the
"Pump Data" section of Volume 9 of the Plant Manual.
No discrepancies were identified.
No violations or deviations were identified.
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 generally aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
ALARA consider ation was found to be an -integral part of each Radiation Work Permit.
No violations or deviations were identifie 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.
During lunch hours in the cafeteria of the Administration Building, the inspector observed an individual, badged as requiring escort, walking unescorted down the hallway from the elevator area to the table area in
.
the lunch room.
The individual proceeded to a table and then eventually continued on into the main cafeteria food service area.
Since the cafeteria is within the protected area of the plant, the inspector questioned the individual as to the whereabouts of his escort.
The inspector ascertained that at the time the individual was walking down the hallway unescorted, the escort was on the other side of the hallway wall in the cafeteria food service area.
Obviously, the individual required to be escorted was not under the control of the escort, as required by plant security procedures'his is an apparent violation of security procedure SP-403(G).
Additional details are-withheld due to the security nature of the material (Enforcement Item 275/87-44-01).
s.
One violation was identified and no deviation was identified.
Plant Confi uration Control Recently, several examples of inadequate configuration control measures became apparent to the inspectors.
These examples were:
1/8/88 DB-50 reactor trip switchgear missing seismic brackets (not reinstalled after maintenance
- reference Nonconformance report (NCR) DCO"88-EM-N005.
ll/10/87 Unit 2 inoperable main steam seismic restraint (due to maintenance activities) when required to be operable-reference NRC IR 50-323/87-43.
'
ll/4/87, Missing seismic interaction restraints required on certain control room post accident monitoring chart recorders-reference NCR DC0-87-TI-117.
10/20/87 Missing seismic support plates on all Unit 1 and Unit 2 containment hydrogen monitors reference NRC IR 50-275/87-38.
The inspectors discussed these situations with plant management and emphasized the need for the plant staff to have an understanding of design requirements and intent of original plant design features and basis.
It was stressed that the impact of changes to the plant must be carefully considered, actions taken must be approved and documented, and information concerning the changes must be transmitted to all affected persons and organizations.
Apparently, PG8E's configuration control system was not providing these feature In the discussions, PG8E management indicated agreement that an assessment of the present configuration control system was necessary, and that a more effective program was required.
In October 1987, PGKE's General Office Nuclear Pl'ant Review and Audit Committee appointed a
Management Oversight Committee to evaluate the configuration control system at Diablo Canyon and issue recommendations, as required.
As of the end of this inspection report. period, the basis for evaluation of the configuration control system was being developed, and members of the committee were being educated on configuration control practices recommended by EPRI, INPO, ANSI and NRC guidance.
Also, an assessment of the constituent elements of the present program was underway.
Conceptual framework for the program assessment was, expected to be completed by early February 1988.
The inspectors will monitor the licensee's progress on this subject.
No violation or deviations were identified.
Root Cause Anal sis and Corrective Actions PG8E letter number DCL-87-136 to the NRC, dated June 15, 1987, described corrective actions to be taken by the licensee to enhance problem root cause evaluation and determination of corrective actions.
Specified corrective actions included the Vice President, NPG, issuing a
memorandum, dated January 8, 1987, on the importance of determining root cause and effecting timely resolution of problems.
That memorandum indicated each individual must take personal responsibility to aggressively participate in the identification, investigation, and resolution of problems.
II'uring the time period since June 1987, improvements in the licensee s
root cause analysis and corrective action program were apparent.
However, additional management attention is required to increase the plant staff's awareness of the need to thoroughly investigate and understand unresolved plant problems'ach problem must be approached in a conservative and well thought out manner, and a definitive, plausible mechanism must be identified.
Several recent examples of inadequate root cause analysis are provided, as follows:
10/20/87 Unit 1 rod position deviation monitor inoperable - reference LER 87-019.
Cause of "P-250 Rx Alm Axial Flux/Rod Pos" annunciator window clearing was not yet determined at the end of this report period.
12/13/87 Unit 1 reactor trip with steam dump instabilities - reference NRC IR 50-275/87-42.
NRC prompting required for proper root cause analysis and corrective actions.
12/13/87 Failure of source range channel detector voltage supply-reference LER 87-24.
Root cause of power supply failure undetermined as of January 30, 1988.
1/26/88 Potential inadequate technical resolution on reply to Notice of Violation (See section 12. a of this report).
~
Considering the above examples, it is apparent that licensee management must take the additional. steps necessary to create a proper atmosphere where staff members individually insist upon a thorough explanation and in-depth understanding of plant problems.
No violations or deviations were identified.
10.
Licensee Event Re ort Follow-u
'a ~
Status of LERs Based on an in-office review, the following LERs were closed out by the resident inspectors:
Unit 1:
87-25 Unit 2:
86-22, 87"10, 87-19 The LERs were reviewed for event description, root cause, corrective actions taken, generic applicability and timeliness of reporting; The LER identified below was also closed out after in-office review and onsite follow-up inspection was performed by the inspectors to verify licensee corrective actions:
Unit 2:
87-. 17 No violations or deviations were identified.
ll.
Startu and 0 eration Ph sics Testin Pro ram a.
Control Rod Worth Measurements The inspector reviewed procedures used and data obtained during the Unit j. and Unit 2 restart from refueling regarding control rod worth measurements.
STP R-31 was used for determining integral rod bank worth using the rod swap method.
STP R-32 was used for determining integral and differential rod worth.
The inspector reviewed the revisions of these procedures used for the startup from refueling of both Unit 1 and Unit 2.
Both procedures established the appropriate prerequisites, precautions and limitations.
These steps established reactor power level, moderator temperature, RCS pressure, control rod alignment, RCS chemistry monitoring, control, and limitation, and applicable Technical Specification requirements.
The inspector witnessed the performance of STP R-31 and STP R-32 as documented in Inspection Report Nos.
50-275/86-32 for Unit 1, and 50-323/87-26 for Unit 2.
The inspector also performed selective data review of all four tests.
No significant calculation errors were found.
The inspector
did note that an independent review was performed on all tests and that a number of corrections were made by the reviewer.
No violations or deviations were identified.
12.
Enforcement Item Follow-u a.
Containment Fan Cooler Unit Condensate Leak Detection S stem (50-323 87-38-01 Closed)
On January 26, 1988, the licensee responded to a Notice of Violation contained in NRC Inspection Report 50-275/87-38 and 50-323/87-38 regarding lack of surveillance acceptance criteria for the containment fan cooler unit (CFCU) condensate leak detection system.
The letter stated:
"Procedure ARP PK-0117 has been further revised to incorporate a method of baselining the CFCU condensate collection system data against the reactor coolant system inventory balance.
This baseline provided the operators with the, capability to correlate CFCU condensate collected to a leak rate."
The inspector reviewed ARP PK-0117, Revision 7, issued January 28, 1988.
According to this procedure, the CFCU standpipe hi to hi-hi alarm frequency would be baselined taking condensate collected in a CFCU standpipe and comparing, it to RCS leakage derived the reactor coolant system inventory balance.
This method of baselining did not take into account. other possible sources of condensation such as secondary side steam leakage.
If other sources of condensate were present during the baselining of the standpipe hi to hi-hi alarm frequency, they could effectively mask a true rise in RCS leakage.
Therefore, the action frequency could potentially be. set unconservatively low such that no action is taken with a greater than one gallon per minute RCS leak existing.
The inspector discussed this finding with representatives of operations, engineering, and regulatory compliance.
At the end of the report period, the licensee was in the process of re-writing ARP PK-0117.
A previous attempt had been made at applying acceptance criteria to the CFCU condensate leak detection system.
Following the issuance of ARP PK-0117, Revision 6, a licensee regulatory compliance engineer noted that the method used could also result in an unconservatively low leak detection frequency.
Both Revision 6 and Revision 7 to ARP PK-0117 had been reviewed and approved by the Plant Safety Review Committee (PSRC).
The enforcement item is closed, but the adequacy of the licensee's corrective actions will be evaluated in subseqeunt inspections (unresolved item 50-323/87-45-02).
b.
Residual Heat Removal Crosstie Valve Enforcement Item 87-13-01 Closed)
In NRC Inspection Report 50-323/87-12, a Notice of Violation was issued against Unit 2 for the licensee's failure to take prompt
corrective action regarding closure of a Residual Heat Removal (RHR)
crosstie valve.
As corrective action in response to the violation (letter number DCL-87-134), the licensee indicated Onsite Safety Review Group Procedure NOS 5.4 and plant Administrative Procedure C-14 Sl would be revised.
The inspector reviewed the procedures and determined the corrective actions described were completed.
Accordingly, this open item is closed.
No violations or deviations were identified.
13.
Exit On February 5, 1988, 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 repor