IR 05000352/1986009
| ML20206Q379 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 06/25/1986 |
| From: | Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206Q374 | List: |
| References | |
| 50-352-86-09, 50-352-86-9, NUDOCS 8607030133 | |
| Download: ML20206Q379 (18) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 86-09 Docket No. 50-352 l
License No. NPF-39 Priority --
Category C Licensee: Philadelphia Electric Company
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2301 Market Street
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Philadelphia, Pennsylvania 19101 J
Facility Name:
Limerick Generating Station, Unit 1 Inspection Conducted: April 14 - May 31, 1986 Inspectors:
E. M. Kelly, Senior Resident Inspector S. D. Kucharski, Resident Inspector B. Hillman, Reactor Engineer Reviewed by:
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J. E. Beall, Project Engineer
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Approved by:
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R. M. Gallo, Chief, Reactor Da'te Projects Section 2A i
f Inspection Summary:
Inspection Report No. 50-352/86-09 for Inspection
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Conducted April 14 - May 31, 1986.
Area Inspected:
Routine daytime and backshif t inspect, ions (328 hours0.0038 days <br />0.0911 hours <br />5.42328e-4 weeks <br />1.24804e-4 months <br />) of j
Unit 1 by the resident inspectors consisting of followup on outstanding items; system walkdown of selected systems using PRA guidance; plant tours including
fire protection measures; maintenance and curveillance observations; and
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review of LERs and periodic reports.
Events which occurred during the period, i
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and were reviewed, include:
low level scram signals on May 2, Inadvertent LOCA signals on May 12, and opening of both Reactor Enclosure equipment air
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lock doors on May 13.
No violations were identified. Unresolved. items are discussed regarding the
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control of' transient combustible materials (Detail 3.3) and the setting and '
storage of replacement MSRVs (Detail 8.0).
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DETAILS
j 1.0 Persons Contacted
Philadelphia Electric Company
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J. Corcoran, Engineer-In-Charge, Field QA J. Doering, Superintendent of Operations
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l R. Dubiel, Senior Health Physicist P. Duca, Technical Engineer J. Franz, Station Manager
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G. Leitch, Superintendent, Nuclear Generation Division
Also during this inspection period, the inspectors discussed plant status and operations with other supervisors and engineers in the PECO, Bechtel
and General Electric organizations.
i 2.0 Followup on Unresolved Items 2.1 (Closed) Unresolved Item 85-23-01: Training of Chemistry Technicians in RMMS Data Entry Calculations of dose contributions from plant radioactive effluents to unrestricted areas are performed using the methodolcgy specified in the Offsite Dose Calculation Manual (ODCM). Chemistry group
personnel are responsible for effluent sampling and analysis, and
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l for entering the effluent data in the Radiation Meterological
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Monitoring System (RMMS) computer system. The calculations are
performed by the Health Physics Group.
- Discussions with both chemistry and health physics personnel during NRC Inspection 50-352/85-23 indicated that only one chemistry group person is responsible for entering the effluent data into the computer.
Data was not being entered into the computer promptly, and dose calculations could therefore not be performed in a timely manner because of the delay in data entry, i
Additional chemistry personnel were trained in data entry and use of i
the RMMS computer system. The inspector reviewed training records for five additional employees concerning data entry to the RMMS i
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computer system.
The inspector had no further questions, and
considered this item closed.
l 2.2 (Closed) Unresolved Item 85-13-01; Small Volume Liquid PASS Sampling The error associated with the dilution of a 0.1 m1 sample with 10 ml
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of demineralized water using the Post-Accident Samping System (PASS)
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was identified in NRC Inspection 50-352/84-66 and a commitment was l
documented in Inspection 85-13 to resolve the problem prior to the i
completion of power ascension testing, i
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i The inspector reviewed Chemistry Group memoranda dated January 29
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and February 25, 1986 which contained the results of five small volume diluted PASS samples drawn on January 26, 1986 and compared
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to a large undiluted reference sample to determine the actual volume of the sample ball valve and the actual dilution.
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j The test results indicated that the ball valve was leaking, and the
valve was replaced under maintenance request (MRF)-86-1057. The volume of sample contained within the ball valve was confirmed to be i
0.1 ml prior to installation.
The inspector discussed this problem
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with Chemistry personnel, including the test results, the dilution volume, and the replacement of the ball valve. The inspector had no
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further questions and considered this item closed.
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i 3.0 Review of Plant Operations
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l 3.1 Summary of Events
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The plant operated at full rated power through May 2, 1986. A planned shutdown was commenced on May 2, 1986, and a six-week scheduled outage was begun to perform certain maintenance, modifi.
cations, and surveillance testing.
3.2 Operational Safety Verification i
The inspector toured the control room daily to verify proper manning,
access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators was reviewed. Nuclear
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instrument panels and other reactor protective systems were examined.
Effluent monitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the protected area and vital island, the inspector
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observed access control, security boundary integrity, search activities', escorting and badging, and availability of radiation monitoring equipment including portal monitors. No unacceptable
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conditions were found.
The inspector reviewed shift superintendent, control room supervisor, and operator logs covering the entire inspection period.. Sampling
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reviews were made of equipment trouble tags, night orders, and the
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temporary circuit alteration and LCO tracking logs. The inspector also observed shift turnovers during the period.
The operations activities were observed for conformance with the applicable proce-dures and requirements; no unacceptable conditions were noted.
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3.3 Station Tours The inspectors toured accessible areas of the plant throughout this inspection period, including: the Unit I reactor and turbine-auxiliary enclosures; the main control and auxiliary equipment rooms; emergency switchgear and cable spreading rooms, and the plant site perimeter.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment. No unacceptable conditions were found.
The inspectors found a small amount of combustible material stored in a zone on Reactor Enclosure elevation 217 designated as a Combustible Fre~e Area. The storage and/or handling of transient combustibles in such zones is prohibited by Administrative Procedure A12.2, and this item is unresolved pending review of the control of transient materials (50-352/86-09-01).
3.4 System Walkdown Using PRA Guidance 3.4.1 AC/DC Electrical Power Safeguard (EPS) System The inspector performed a modified system walk down of the Electrical Power Safeguard (EPS) System utilizing the method prescribed in a study prepared for the NRC by Brookhaven National Laboratory - Limerick Generating Station Unit 1 Probabilistic Risk Assessment - Based System Inspection Plan, February 1986.
The basis behind this study is to provide inspection guidance, utilizing the Limerick Final Safety Analysis Report. The study has prioritized plant safety system with respect to their importance. Also provided, is an abbreviated version of the licensee's system checklist which contains components that are considered to have a high risk factor for PRA.
The modified system walkdown for the EPS system was per-formed in three areas, the Control Room, Diesel Generator Room, and the Battery Rooms.
In the control room the inspector verified that power is available to the four 4kV buses, the 440V AC buses and to the four 125/250V DC buses.
The inspector also verified that all diesel generator (OG)
alarms were cleared and that offsite power is available.
The inspector performed the walkdown of all the DG rooms during the inspection period. The inspector verified the following conditions:
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The'DG local / remote selector switch was in the correct position.
i The ventilation fan switches were correct.
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-Governor oil level was satisfactory,
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Air receiver tank pressure was at the required
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pressure.
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Fuel oil day tank level was within the required
limits.
Emergency Service Water (ESW) manual discharge valve
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was throttled open and locked into position.
The final phase of the walkdown involved all four division
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battery rooms. The inspector. verified that the input and
output breakers at each battery charger are closed and
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that the supply breaker to the battery chargers were positioned correctly.
No unacceptable conditions were l
identified, i
3.4.2 High Pressure Coalant Injection (HPCI) System q
The-inspector verified the operability of the High i
Pressure Coolant Injection (HPCI) system by performing j
reviews in selected areas important to system reliability j
as indicated in the Limerick PRA Inspection Guidance l
Appendix.
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The inspector reviewed the following' completed
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surveillances:
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ST-1-055-202-1 HPCI Cold Shutdown Valve Test,
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performed January 4, 1986
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ST-6-055-200-1 HPCI Valve Test, performed February 6,
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ST-6-055-230-1 HPCI Pump Test, performed February 26,
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1986 ST-1-055-100-1 HPCI Logic' System Functional Test,
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performed May 6, 1986
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No maintenance has been performed on the turbine pump unit i
since the performance of the most recent pump functional i
test. The inspector reviewed all outstanding work request i
files for items that could affect system reliability.
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The inspector performed a walkdown of the portions of the system identified in the PRA as important to system reliability and confirmed the following items:
identification of equipment conditions and items that
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might degrade performance PRA identified valves and breakers were properly
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aligned, necessary instrumentation is functional, and appropriate valves were locked.
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Control Room switches, indicators, and controls are satisfactory.
No unacceptable conditions were identified.
4.0 Event Followup 4.1 Low Level Scram Signal Following Controlled Shutdown The licensee manually scrammed the reactor from 28*4 power at 7:38 p.m. on May 2, 1986 after a controlled shutdown begun at 5:00 p.m.
for the 6-week outage. During the subsequent cooldown, an unplanned automatic scram signal occurred at 8:03 p.m. on low reactor vessel level.
Level was being controlled with the 'C' feedwater pump in manual, due to the unavailability of the startup level control valve because of a piping leak in the 'A' pump minimum flow line to the condenser.
The reactor was at approximately 700 psig when level oscillations occurred and the low level scram setpoint was reached. All control rods were fully inserted at the time, the scram was reset, and plant depressurization was continued.
Cold shutdown was achieved at 6:11 a.m. on May 3 and outage testing and maintenance was begun. The resident inspector observed the manual scram and subsequent cooldown evolution.
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Reactor water level at low power is normally controlled using the automatic level control valve on the 'A' feed pump. However, beca'use of the leak on the minimum flow piping for the 'A'
pump, reactor water level was manual,1y controlled using the 'C'
RFP which is not equipped with an automatic level control valve. At lower feedwater flows (below 0.5 million Ib/hr), feedwater flow indicators indicate zero flows, and the operator relies upon reactor water level instrumentation in making adjustments to RFP flow and pressure. The feedwater discharge valve was throttled and pump speed was decreased to control a reactor water level increase. When reactor water 19 vel was observed to decrease, the operator responded by increasing the
'C' RFP speed in steps but not enough to maintain level above the low e
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level scram setpoint. Actual vessel water level at which the scram
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signal occurred was 14.5 inches; the lowest level reached was 13.5 inches before level was recovered.
The resident inspector discussed this event with licensed operators and Operations supervision.
Sufficient preparation had been made for the controlled shutdown, and the licensee had made operators
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aware of the difficulty in controlling level without use of the 'A'
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4.2 Improperly Installed Jumpers
At 1:00 a.m. and 6:50 a.m. on May 3, unplanned initiations of the
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Standby Gas Treatment System (SGTS) occurred during surveillance
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testing due to an improperly installed jumper and a blown fuse. The 1:00 a.m. initiation started the 'A' SGTS fan, and the 6:50 a.m.
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initiation started the 'B' fan.
In each case, as expected, normal reactor enclosure ventilation remained in service and a secondary
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containment isolation did not occur.
The licensee made ENS calls to l
l the NRC. The resident inspectors discussed the cause of these events with I&C engineers and supervision. The causes were attributed in
both cases to cognitive personnel errors by I&C engineers involved q
in the testing in that the jumpers were connected to the wrong termination points in the first case, and were inadvertently grounded
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in the second case. No violations were identified.
4.3 Division 2 ECCS Actuation Signal
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i A Division 2 ECCS actuation signal was initiated at 9:52 a.m. on May 12, 1986 as a result of surveillance testing.
The reactor was in j
the Cold Shutdown conditiori at the time, and the plant was beginning i
the second week of a 6-week surveillance test outage.
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Following calibration of a reactor vessel pressure transmitter, I&C
technicians placing the transmitter back in-service by venting caused a perturbation on a common reference leg which generated a Level 1 i
(minus 129 inches) reactor vessel level signal.
ECCS Division 2 logic created start signals for
'B' RHR and Core Spray but, because
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these systems were blocked for maintenance, no injections occurred.
Emergency diesel generator (EDG) 12, which was running at the time
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j and was 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> into a 24-hour test run, had its cutput breaker l
opened and received the expected load shunt trips. The EDG 12 test
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run was begun again on 5/12.
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All systems operated as expected, and the licensee reported this event via the ENS phone to the NRC at 2:04 p.m. on 5/12. The resident inspector discussed this event with plant management and I and C supervision. The test procedure ST-2-042-462, for the 18-month calibration of reactor vessel pressure transmitter PT-42-103B, contained misleading direction as to where to connect the test pressure source and indicator. The procedure referred to the "Hi Side Vent" but Figure 1 of the procedure did not label that connection.
Further, another (unreferenced and not depicted on Figure 1) test connection existed underneath of the transmitter high pressure (process) leg. The I and C technician connected to and used that connection to perform the calibration, which resulted in drain-ing the transmitter. Upon restoration to normal following the cali-bration, the venting of the transmitter caused the signal to occur.
The licensee committed to making a procedure change and reviewing this event with technicians.
The inspector had no further questions.
4.4 Loss of Shutdown Cooling A shutdown cooling isolation occurred at 2:15 a.m. on May 13 caused
by an I&C technician error while restoring logic associated with surveillance testing on reactor vessel dome pressure instrumentation.
Upon return of power to the HV-1F009 shutdown cooling suction valve, the valve closed and the associated RHR pump tripped, because of a failure to follow the surveillance procedure to properly restore the logic. The containment isolation valve was reset, shutdown cooling was returned to service, and the licensee completed the surveillance testing.
The reactor was in cold shutdown at the time, in the second week of a 6-week outage.
The inspector discussed this event with plant operators and I&C supervision. The licensee committed to appropriate procedure changes. No violations were identified.
4.5 Simultaneous Opening of Both RE Airlock Doors A Reactor Enclosure (RE) isolation occurred at 3:25 p.m. on May 13 due to simultaneous opening of both Unit 1 RE equipment access airlock doors. The inner door had been open in preparation to remove mainsteam safety relief valves from the building.
Personnel then opened the outer door, and RE pressure increased to the isolation setting, causing SGTS and RERS to initiate.
The isolation was reset at 3:40 p.m.
The resident in,spector discussed this event with licensee personnel, and chain locks were subsequently added to the doors, the keys to which will be controlled by shift supervision. Signs were also
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added to direct contacting shift supervision prior to opening both doors.
No violations were identified, and the inspector had no
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further questions.
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5.0 Licensee Reports 5.1 In-Office Review of Licensee Event Reports The inspector reviewed Unit 1 LERs submitted to the NRC Region I office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action..The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site followup.
The following LERs were reviewed:
LER Number Report Date Subject 86-012 March 14 RHR Service Water Radiation (Note a)
Monitor.Downscale Failure and Isolation 86-014 March 27 Reactor Enclosure Isolation due (Note a)
to Breach in Equipment Access Airlock 86-016 April 24 Technical Specification violation due to Surveillance Testing (Reactor Enclosure HVAC)86-018 May 2 Technical Specification Firewatch violation due to Missing Penetration Plugs86-019 May 5 Failure to meet an. hourly fire watch requirement 86-020 June 2 Low Level Scram Signals
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(Note b)86-021 June 2 Inadvertent ESF Actuation of SGTS due to Improper Use of Jumpers Notes:
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Addressed in Detail 5.2 of this report b.
Addressed in Detail 4.1 of this report
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5.2 Onsite Followup of Licensee Event Reports For.those LERs selected for onsite followup as noted in Section 4.1, the inspector verified the reporting requirements of 10 CFR 50.73
and Technical Specifications had been met, that appropriate
i corrective action had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
5.2.1 LER 86-012: RHR Service Water Radiation Monitor Failures During this inspection the following procedures were i
reviewed:
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ST-2-012-400-0, Radiation Monitoring - RHR Service Water Radiation Monitor, Division I, Channel A Calibration / Functional Test, Revision 2, February 10, 1986
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ST-2-012-401-0, Radiation Monitoring - RHR Service Water Radiation Monitor, Division II, Channel B Calibration / Functional Test, Revision 2, January 29, 1986 ST-2-012-402-0, Radiation Monitoring - RHR Service
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Water Radiation Monitor, Division III, Channel C Calibration / Functional Test, Revision 2, January 29, 1986 ST-2-012-403-0, Radiation Monitoring - RHR Service
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Water Radiation Monitor, Division IV, Channel D Calibration / Functional. Test; Revision 2, February 10,
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ST-2-012-600-0, Radioactive Liquid Effluent Monitoring - RHR Service Water Radiation Monitor; Division 1, Channel A Functional Test, Revision 4, October 23, 1985
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ST-2-012-601-0, Radioactive Liquid Effluent Monitoring - RHR Service Water Radiation Monitor; Division II, Channel B Functional Test, Revision 4, October 23, 1985
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ST-2-012-602-1, Radioactive-Liquid Effluent Monitoring - RHR Service Water Radiation Monitor, Division III, Channel C Functional Test, Revision 5, January 29, 1986
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ST-2-012-603-1, Radioactive Liquid Effluent
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Monitoring - RHR Service Water Radiation Monitor, Division IV, Channel D Functional Test, Revision 5, January 29, 1986 It was identified by the licensee that the installed circuitry of the RHR service water (RHRSW) system effluent radiation monitor would not cause an automatic isolation of the RHRSW system in the event of a downscale failure.
The licensee immediately declared all four monitors inoperable and performed the appropriate action statements which involved collecting grab samples and analyzing them for gross radioactivity every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
A review was performed by the licensee to determine if similar problems existed in other systems. This review process revealed an additional problem with the RHR System
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The existing circuitry at that time did provide isolation from a low high voltage condition but did not provide a control room alarm if the event occurred. This failure
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could have caused'a system isolation that would not have been recognized as being caused by the radiation monitors.
The inspector discussed the changes with the licensee's I and C personnel and reviewed modification package 85-0704 implemented on March 13, 1986. M00-85-0704 incorporated the required circuitry changes to implement both the automatic isolation for a downscale circuit failure, and the control room alarm for the "inop circuit failure".
Following the changes made the licensee performed the channel functional test listed above to assure operability. The inspector had no further questions.
5.2.2 LER 86-014:
Reactor Enclosure Isolation Due to Breach in Equipment Access Airlock On February 27, 1986 while the plant was in operational mode 1 at 100 percent power, a reactor enclosure isolation occurred, along with activation of the Reactor Enclosure Recirculation System (RERS) and the Standby Gas Treatment System (SGTS). This isolation occurred due to the opening of both the inner and outer equipment airlock doors on the 217' elevation. The doors were allowed to be open to move construction equipment without notification to operations.
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The inspector reviewed the corrective action plan with the licensrc which involved the Engineering and Research Department investigating the aspect of installing a local warning light and horn and a remote annunciator in the main control room. The inspector also reviewed Post Orders No. 21, Compensatory Post-Portal, Revision 9, March 25, 1986 which was changed to alert the security force members, who will be involved in the future, not to have both airlock doors (No. 195 and 203) open at the same time. No unacceptable conditions were identified.
5.3 Review of Periodic and Special Reports Upon receipt, periodic or special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed to determine that the report included the required information, that test results and/or supporting information were. consistent with design predictions and performance specifications, and whether any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Special Reporting Requirement - Seimic Monitoring
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instrumentation inoperable for more than 30 days, March 18, 1986
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Monthly Operating Report for March, 1986
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1985 Annual Report describing the implementation of the Environmental Plan, April 28, 1986
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1985 Annual Radiological Environmental *0perating Report #2, April 28, 1986 These reports were found acceptable.
6.0 Local Leak Rate Testing (LLRT)
6.1 Documents Reviewed
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ST-1-LLR-001-1, the LLRT Program and Accountability Test, Revision 3, March 6, 1984
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ST-1-LLR-002-1, Primary Reactor Containment Test Tap LLRT, Revision 0, September 30, 1983
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ST-1-LLR-731-1, Core Spray Pump Minimum Recirc, Revision 3, April 16, 1986
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ST-1-LLR-481-1, "D" RHR LPCI, Revision 4, April 16, 1986
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ST-1-LLR-621-1, RHR Pump "D" Suction, Revision 2, March 17,
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1986 LGS Related Technical Specifications
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LLRT Calibration Records
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LLRT Results Record of Running Total
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Selected piping and instrumentation diagrams i
6.2 Scope of Review The inspector reviewed the above documents to ascertain compliance with Regulatory Requirements of 10CFR50, Appendix J, Limerick Generating Station, Unit 1 Technical Specifications, applicable industry standards and station administrative guidelines. The inspector also witnessed local leakage testing, held discussions with the licensee regarding the documentation of test results, the repair and retesting following failed tests, if applicable, and the relationship of these items to the "As-Found" and "As-Left" condition of containment as applied to Containment Integrated Leak Rate Test (CILRT) results.
6.3 Procedure Review The procedures reviewed were technically accurate and in conformance with the regulatory requirements of Appendix J to 10CFR50 and appli-cable indur.try standards.
The Performance Engineer and his alternate and associated licensee personnel have inspected piping configurations to assure that the appropriate line-up drawings are referenced in the LLRT procedures, and the system line ups in the procedures are accurate and in accordance with leakage testing. requirements.
No unacceptable conditions were identified.
6.4 Test Witnessing During this inspection period the inspector witnessed three type C LLRT. They were as follows:
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Core Spray pump minimum Recire, Penetration X-208B, valve HV-52-1F031B 2.
RHR Pump "D" Section, Penetration X-203D, valve HV-51-1F004D 3.
"D" RHR LPCI, Penetration X-450, valve HV-51-IF017D
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The tests were run according to applicable procedure as stated in Section 5.1.
The inspector verified that the tests were being con-ducted in accordances with the. procedures, and that the technicians involved in each test were knowledgeable of requirements and use of
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the test instruments.
No unacceptable conditions were identified.
6.5 LLRT Instrument Calibration The inspector reviewed the calibration records for the LLRT instru-ment boxes. Also reviewed were the calibration records of the standards used to calibrate the test instrumentation.
During the review process the inspector noted that three of the five LLRT instrument boxes had a consistent history of being out of calibration at the calibration due date.
The calibration period for this instru-mentation is a one-month period or when needed. Presently, when this problem occurs the I and C group writes an "Out of Cal" report to the
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QC Department which in turn starts an investigation with the test i
engineers to verify if the results are acceptable.
If the data is questionable the test is re performed. The inspector questioned the licensee regarding the problem with the instrumentation, the licensee has committed to review the calibration frequency of the instrument boxes. There were no further questions at this time.
6.6 T_est Results
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The inspector reviewed the LLRT results summary. The review process included the licensee's treatment of the "As-found" and "As-Left" test condition, the analyses of test failures, repairs, and retests.
The licensee at this time keeps a running total of the LLRT in which the condition of the containment is known at.all times.
No unacceptable conditions were identified.
7.0 Maintenance and Surveillance Activities 7.1 Maintenance on D-14 Generator During this inspection period the. licensee'has performed inspections and maintenance activities on all four diesel generators. These activities were required by technical specifications based on an eighteen month surveillance schedule.
The inspector reviewed the following completed Maintenance and Preventive Maintenance procedures:
M-020-001, Diesel Generator Eighteen Month Examination and
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Maintenance, Revision 0, April 7, 1986
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Maintenance, Revision 3, April 28,1986 M-020-009, Diesel Engine Main and Connecting Rod Bearing
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Examination and Maintenance, Revision 0, May 5, 1986 M-020-015, Diesel Engine Cooling System Hydrostatic Test,
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Revision 0, April 30, 1986
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PMQ-011-006, Preventive Maintenance Procedure for Diesel
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Generator Lube Oil Cooler E-506, Revision 0, August 16, 1984 PMQ-011-007, Preventive Maintenance Procedure for Diesel
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Generator Jacket Water Heat Exchanger Clean and Examine E-507,
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Revision 0, August 16, 1984
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PMQ-020-009, Preventive Maintenance Procedure for Diesel Engine
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Jacket Water Cooling System 5 inch Check Valve Examination and Maintenance, Revision 0, April 30, 1986.
i Work was performed in accordance with the above procedures.
Maintenance data record forms were properly documented. and approved,
.i and all the required hold points were checked by QC and properly-signed-off as required.
The inspector witnessed various portions of the above procedures during the tear down and inspection of the D14 diesel generator.
The vendor representative, and the licensee's QC personnel were present during the maintenance and inspection.
Personnel performing
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the work were knowledgeable and have sufficient work experience in this area to adequately perform their assignments. No unacceptable conditions were identified.
7.2 Surveillance Activities 7.2.1 The inspector observed the performance of/or reviewed the results of the following tests:
ST-1-092-112-1, D12 Diesel Generator 4 KV SFGD Loss
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of Power LSF/SAA and Outage Testing, Revision 3, May 8, 1986 ST-1-072-101-1, DIV I NSSSS LSF/SAA, Revision 2,
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May 2, 1986
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ST-6-095-902-1, DIV II 125/250 VDC Safeguard Battery i
Weekly Inspection, Revision 10, May 5, 1986 i
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ST-3-048-320-1, SBLCS Operability Verification and
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Valve Test, Revision 2, May 20, 1986
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ST-3-048-230-1, SBLC Pump, Valve and Flow Test
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Revision 7, May 12, 1986 The tests were observed to determine that test procedures conformed to Technical Specification requirements; proper administrative controls and tagouts were obtained prior to testing; testing was performed by qualified personnel in accordance with approved procedures and calibrated instrumentation; test data and results were accurate and in accordance with Technical Specifications; and, equipment was properly returned to service following testing.
No unacceptable conditions were identified.
8.0 Target Rock Safety Relief Valve Test Failures During the week of May 5, 1986, the licensee removed all fourteen Main Steam Safety Relief Valves (MSRVs) and sent them to be tested at Wyle Laboratory. Although the Technical Specifications only require one-half of the SRVs to be tested once per 18 months, because of time restraints and the possibility of failing the one percent of nominal lift pressure criteria (based on BWR experience), all 14 valves were sent for testing.
8.1 Test Results Ten of the fourteen valves failed to lift within +/- 1% of-the nominal lift setting required by Technical Specifications.
Five of the failed valves exceeded the 103% ASME Code limit. The maximum setpoint variance was 7%. The mean value of setpoint nameplate-was 2.6% for the "as-found" first lift and 0.7% for subsequent lifts, as shown in the tabulations below:
Previous
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Serial No.
Date of Certified Nameplate As Found Lift
%
(SRV)
Test Setpoint (psig) Setting (psig) Pressure (psig) Variance
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First Batch
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517 (A)
5/12 1154 1150 1154
+0.4
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525 (C)
5/13 1144 1150 1198
+4.2 513 (G)
5/12 1153 1150 1184
+3.0 515 (K)
5/13 1131 1140 1188
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+4.2 522 (M)
5/13 1148 1140 1220 (Note a)
+7.0 528 (S)
5/12 1131 1140 1140
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523 (H)
5/12 1135 1130 1165
+3.1 518 (J)
5/13 1127 1130 1160
+2.7
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Second Batch 516 (N)
5/27 1133 1130 1153
+2.0 521 (L)
5/27 1133 1130 1159
+2.6 519 (F)
5/28 1145 1150 1153
+0.3 527 (E)
5/28 1137 1140 1187
+4.1 526 (D)
5/27 1142 1140 1129-0.97 520 (B)
5/29 1161s 1150 1178
+2.4 Serial Nominal As-Found Subsequent Lifts Number Sat Pressure Lift / Reseat (psig)
(psig)
(psig)
2nd 3rd 4th
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517 1150 1154/812 1155 1148 1145 525 1150 1198/783 1149 1140 1140 513 1150 1184/797 1153 1142 1140 515 1140 1188/923 1127 1137 1138 522 1140 1220/976 1145 1136 1135.
528 1140 1140/786 1139 1133 1127-523 1140 1165/790 1145 1138 1125 518 1130 1160/806 1125 1125 1122 516 1130 1153/785 1146 1136 1141 521 1130 1159/833 1155 1145 1143 519 1150 1153/783 1147 1147 1141 527 1140 1187/796 1136 (Note b) (Note b)
526 1140 1129/867 1145 1136 1128 520 1150 1178/817 1165 1160 1157 NOTES as-found first setpressure greater than 1190 psig, full-scale a
instrumentation limited to 1200, extrapolated to 1220 psig for SRV S/N 522 b
only 2 lifts for SRV S/N 527; suspected defective due to delay times between pilot and main disc movement greater than 300 microseconds (380 usec initial, 540 usec 2nd)
All 14 valves tested had been refurbished in February 1984 including inspection in the labyrinth seal area and the enhanced valve inter-nals maintenance program. The tested valves were also manually cycled open for 10 seconds during the startup test program at Lime-rick; once during the heatup phase at 358 psig (427 degrees F) and 4.8% power on January 6, 1985, and again during Test Condition 2 at rated pressure of 956 psig (510 degrees F) and 25.5% power on January 6, 1985.
The valves had been installed through the Startup Test Program.
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8.2 Replacement Valves The replacement valves re-installed on Unit I were taken from storage; seven from the PEC0 warehouse (Unit 1 spares) and seven from the Bechtel Warehouse (designated Unit 2 spares). Storage of the replacement valves and installation is being evaluated by the resident inspectors and will be followed as item 50-352/86-09-02.
9.0 Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable or constitute a deviation or a violation. Unresolved items are discussed in Details 3.3 and 8.3.
10.0 Exit Meeting The NRC resident inspector discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with Mr. John Franz and others of your staff on May 21 and again on June 2, 1986. At this meeting, the licensee's representatives indicated that the items discussed in this report did not involve proprietary information.
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