IR 05000219/1989012
| ML20247L778 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 07/21/1989 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247L736 | List: |
| References | |
| 50-219-89-12, IEB-85-001, IEIN-84-52, NUDOCS 8908010348 | |
| Download: ML20247L778 (24) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
j Docket / Report No.
50-219/89-12 License No.
DPR-16 Priority --
Category C Licensee:
GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station Inspection Conducted:
April 30 - June 3, 1989 Participating Inspectors:
E. Collins J. Lara D. Lew W. Oliveira R. Paolino 7/AfM Approved By:
w.c m
m, C. Cowgill, Chief, Reactor Pro cts Section 4B Date Inspection Summary-Inspection April 30 - June 3,1989 (Report No. 50-219/89-12)
Areas Inspected:
Routine and reactive inspections by resident and regional-based inspectors (209 hours0.00242 days <br />0.0581 hours <br />3.455688e-4 weeks <br />7.95245e-5 months <br />) were conducted on activities in progress, including: plant operational events including three reactor start-ups (paragraph 2.0); the licen-see's corrective actions with regard to reactor coolant pressure boundary hangers being pinned and evaluation of reverse direction testing of containment isolation valves (paragraph 3.0); review of the plant trip with reactor isolation (paragraph 4.0); review of core spray pump net positive suction head (NPSH) calculations (paragraph 5.0); monthly surveillance observation (paragraph 6.0); local power range monitor observations (paragraph 7.0); review of a security event (paragraph 8.0); and review of previously opened inspection findings (paragraph 9.0).
Results:
The licensee's corrective actions with regard to reactor coolant pressure boundary hangers and reverse testing of containment isolation valves were not ade-quate to correct the deficient conditions and identify steps to prevent recurrence'.
These two conditions highlight weaknesses in the effectiveness of the site's cor-rective action systems.
These conditions are a violation of NRC requirements.
Operator response to this event to stabilize and control plant conditions was good.
In response to the May 18th plant trip and reactor isolation, positive steps were taken by management to improve the control of temporary variations and to improve communications between maintenance and control room personnel.
The weaknesses in the control of pinning hangers and lifting electrical leads show the need to strengthen plant temporary modification control.
Core spray pump NPSH calculations show that when the volume of water retained in the drywell is considered, the mar-gin to NPSH is reduced by about 1/2 foot.
For the limiting core spary pump, net positive suction head is questionable at peak containment temperature.
The lic-ensee evaluated this condition to be acceptable.
In the area of security, weak-ness in security system computer software and the lack of a timely repair to a security system status board contributed to the failure to provide monitoring for a vital area door.
Licensee actions were adequate to address this violation of their security plan.
Thirteen previously opened inspector items were reviewed and closed.
8908010348 890725 (
PDR ADOCK 05000219 l
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l TABLE OF CONTENTS l
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1.0 Li st o f Peopl e C o n t a c ted...........................................
2.0 Plant Operations Review......................
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i 2.1 Reactor Pressure Vessel Hydrostatic Test........................
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2.2 Leaking Electromatic Relief Va1ve...............................
2.3 Plant Startup May 8.................................
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2.4 Plant Startup May 9.............................................
.2.5 Plant Startup May 21...
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3.
2.6 Plant Operations Assessment.....
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3.0 Corrective Action Systems................
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3.1 Reactor Coolant Pressure Boundary Hangers..........
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3.2 Reverse Direction Testing of Containment Isolation Valves.......
3.3 Conclusions..................................................
4.0 Plant Scram With Reactor Isolation...............
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4.1 Event Description...
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4.2 ' Inspector Review of the Event.............................
4.3.1 Overvoltage of 4.16 KV Bus.........................
4.3.2 Loww o f Powe r to tne 4.16 KV Bu s....................
4.3 Electrical Plant Design.
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4.4 Overall Plant Response...
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4.5 Review of Operator Response..............
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4.6 post Trip Review Group Reports.............................. 15 5.0 Core Spray Pumps Net Positive Suction Head........
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6.0 Surveillance Observation..
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7.0 Local Power Range Monitors (LPRM)............
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8.0 Security Event.
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9.0 Review of Previously Opened Inspection Findings..
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10.0 Review of Periodic and Special Reports..
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11.0 Radiation Protection..................
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12.0 Inspection Summary Hours...................................... 22 13.0 Exit Meeting...
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DETAILS 1.0 List of People Contacted
- E. Fitzpatrick, Director Dyster Creek
- E. Scheyder, MCF Director
- R. Barrett, Plant Operations Director A. Rone, Plant Engineer, Director D. Ranft, Elect /I&C/0PS
- J. Deblasio, Mech. Spare Parts Mgr.
G. Busch, Licensing Mgr.
J. Rogers, Licensing K. Barnes, Licensing B. Demerchant, Licensing R. Brown, Plant Operations Mgr.
K. Mulligan, Plant Operations
- R. Thompson, Core Engineering
"R..Ewart, Security C. Schilling, Plant Engineering M. Lamberdo, Plant Engineering P. Smith, Technical Functions J. Lagatto, Technical Functions
- Denotes attendance at exit meeting.
2.0 Plant Operation Review (71707,71711,93702)
2.1 Reactor Pressure Vessel Hydrostatic Test of Core Spray Weld NZ-3-38 On 5/5/89, a reactor vessel hydrostatic test was performed for post maintenance testing. When test pressure reached 1135 psig, uniden-tified drywell leakage rate indicated about 15 gpm and an unusual event was declared.
Plant operators responded by reducing reactor l
pressure and confirming that the leak had stopped.
The unusual event was then terminated.
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The licensee's review identified that safety valves NR-28-A and NR-28-Q had been leaking during the test. These valves have lift set points at 1212 12 psig and 1230 12 psig respectively.
Hydro-static test pressure was at 1135 psig.
Because the valve lift pres-sures were significantly above test pressure, the licensee did not gag the safety valves in the closed position for the hydrostatic test.
The licensee reviewed previous data on these safety valves with the valve manuf acturer and concluded that leakage from water at 1135 psig was not unusual.
The licensee further concluded that there had been no detrimental effects on the valves' set points.
In order to com-plete the test, the licensee changed the hydrostatic test procedure to require gagging of the safety valves. The hydrostatic test was completed satisfactorily on 5/6/89; and, core spray weld NZ-3-38 passed its post maintenance test.
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.NRC inspectors reviewed the licensee's analysis of the leaking safety valves and-response to the unusual event..It was concluded that the Plant' Engineering analysis was thorough, and.the response to the high
' leak rate was appropriate. No unacceptable conditions were identi-fied.
2.2 -Leaking Electromatic Relief Valve
o As a result of.the reactor pressure vessel testing conducted on May 5 and May 6, the licensee observed that suppression pool. level.was in-creasing when the reactor coolant system was pressurized. The licen-
'see's analysis' identified'that the source'of this leakage was from
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.the "A" Electromatic Relief Valve (EMRV). When the valve was re-t moved, the. valve poppet was observed about 3/8-inch opened. This
. opening allowed water to pass from the main steam line to the sup-pression pool.
The valve was replaced.
The licensee has returned'
'the valve to the manufacturer to identify the root cause fcr the failu e of the' valve to close.
NRC inspectors reviewed the licensee's corrective actions for the leaking EMRV.
This condition explains the EMRV exhaust high tempera-ture condition experienced during previous plant operations (Inspec-tion Report 50-219/89-10).
No unacceptable conditions were identi-fied.
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2.3 Plant Startup May 8 A plant startup and plant heatup was performed' on 5/8/89. Plant pro-cedures require isolation condenser condensate return valves to be cycled every '100 degrees during a plant heatup.
Isolation Condenser Condensate Return Valve V-14-35 was cycled at 260 degrees. As the valve moved back to its closed position, the breaker tripped on ther-mal overload.
Plant heatup was stopped; and, the "B" Isolation Con--
denser was declared inoperable. Plant technical specifications re-quire that both isolation condenser subsystems are operable during plant startup.
The plant was shut down and cooled down to repair valve V-14-35.
Inspectors observed portions of the plant start-up, and reviewed the licensee's response to the inoperable isolation condenser. The cause for the failure of valve V-14-35 was a broken pin in the close direc-tion torque switch. The torque switch was replaced; and, the valve tested satisfactorily.
No unacceptable conditions were identified.
2.4 plant Startup May 9 A plant startup and heatup was performed on 5/9/89. With the reactor at normal operating temperature and normal operating pressure, an inspection inside the drywell was performed.
During this inspection.
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two spring czns on the Shutdown Cooling System were discovered in-advertently pinned. Because of a similar occurrence, inadvertently pinned hangers on reactor coolant pressure boundary hangers dis-covered on 4/22/89, the licensee stopped the plant startup and power
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ascension until an adequate evaluation could be made. This event is l
reviewed in detail in paragraph 3.1 of this report.
On 5/10/89 the licensee completed its evaluatien of pin hangers and continued the power ascension and plant startup. The generator was placed on line on 5/11/89.
During the reactor startup and power ascensicn period from May 11 through May 14, 1989, inspectors observed control room activities, shift turnovers and preshift briefings.
The inspector independently performed several manual heat balance calculations to corroborate plant computer core thermal power calculations. No unacceptable con-ditions were identified.
On 5/18/89 while the plant was operating at 3 all power, the reactor scrammed on an anticipatory turbine trip sigral. This event occurred while I.:strument and Control technicians wers calibrating the gene-rator load recorder. Generator reactive loaa indication was lost.
and the control room operator incorrectly responded by increasin; tne t
excitation of the main generator.
This re3ponse resulted in an over excitation trip.
This event is reviewed in paragraph 4.0 of this report.
2.3 Plant Startup May 21 Plant startup and heatup were performa_ on 5/21/89.
The generator was placed on line on 5/22/89, and plant full load was achieved on c/24/89.. The plant operated at essentially full load for the re-mainder of the inspection period.
I On 5/25/89 the plant experienced abnormal control rod motion when rod 46-35 drif ted f rom full out position 48 to position 02. Plant opera-tors responded by performing the actions specified in plant proce-dures.
The control rod was valved out of service at the 02 position and declared inoperable; and, shut down margin verification was per-formed. No unacceptable conditions were identified.
On 5/26/89 both #1 and #2 fire diesels we ? declared inoperable after surveillance testing.
Previously, the redundant fire protection sys-tem had been declared inoperable on 5/24/89.
This rendered all plant fire suppression systems inoperable.
Plant specifications require that a backup fire suppressio.n water system be established within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. At 6:55 a.m. on 5/27/89 the redundant fire protection system was declared operable, and at 3:45 p.m. on 5/27/89 #2 fire diesel pump was declared operable.
These opereoilities satisfied plant
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technical specification requirements. #1 fire diesel remained in-operable while repairs were performed to its supercharger.
The lic-ensee will be submitting two special reports on these events.
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2.6 Plant Operations Assessment Overall, the plant was operated in a safe manner.
Two events, the control of priming primary coolant system hangers and calibration of -
the generator load recorder show wea>aesses in the control of plant work. Both events adversely affected plant operation by' challenging plant operators.
Plant operators responded to these events in an effective manner.
Three plant startups were performed in an controlled and safe manner.
Operations management was directly involved, continuously monitoring control room activities.
3.0 Corrective Action System Weaknesses (93702, 71707)
Two events occurred which indicated ineffectiveness in the licensee's cor-rective action systems.
In the first event, reactor coolant pressure boundary hangers were inadvertently left pinned and a critique did not correct the deficient condition nor identify effective steps to prevent recurrence.
In the second event, an NRC inspector identified, in 1986, a lack of documentation for reverse direction testing of containment-isola-
tion valves.
Technical Function's analysis of this reverse direction testing did not identify that this testing was not conservative.
NRC resident inspectors reviewed these events to assess the extent of weaknesses in the licensee's corrective action systems and the effective-ness of the licensee's initiatives to impose site corrective action sys-tems.
3.1 Reactor Coolant Pressure Boundary Hangers On 4/22/89 it was discovered that one of the reactor recirculation spring can hangers had been lef t pinned from 12R outage work The hanger was unpinned and an analysis concluded that excessive stresses were not imposed on system piping. Two plant heatups had been per-formed in this configuration.
To identify and evaluate the events that led to th s hanger being lef t pinned, the licensee conducted a critique which was observed by an NRC inspet+.or.
The inspector noted discussions addressing addi-tional drywell hanger inspection.
In addition, the inspector noted t' t the root cause had not been clearly established.
During the previous refueling outare a number of primary system hangers were pinned in order to support the installation of temporary shielding to reduce radiation exposure for drywell workers.
The pinning and un-
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l pinning of these hangers inside the drywell was not well controlled
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or documented.
The results of this critione were stated in a cri-tique report dated 5/7/89. No additional hanger inspections were specified.
During a review of the approved critique, Operations management ex-pressed concern to the Maintenance and Construction Facilities (MCF)
Department that additional drywell hangers had not been inspected to verify their configuration. Since a reactor heat up was in progress, it was decided to inspect additional hangers during the drywell in-spection later that day.
This inspection revealed two additional pinned spring can hangers on the shutdown cooling system. Based on these findings, the licensee stopped power ascension until satisfac-tory resolution of the issue could be obtained.
A panel, consisting of senior corporate and site managers and chaired by site director, convened to review the issues associated with the pinning of reactor coolant pressure boundary hangers.
Overall, the panel determined that site policies, procedures and programs provided adequate control for work and temporary variations.
In the area of pinning hangers, the panel had the following conclusions:
The job order was confusing in that the user could not tell from
one revision to the next what work had actually been accomp-lished and what work was required.
The critique conducted by MCF was unacceptable in that the root
cause was not identified, and the corrective action specified was not adequate.
Additional drywell inspections were required to determine the
state of drywell hangers.
These walkdowns were conducted, and no other adverse conditions were identified.
A review of other similar temporary variation conditions was
required to establish adequate confidence in plant physical configuration. No adverse conditions were identified by this review.
The panel proposed the following long-term corrective actions:
Review procedures and controls in place for temporary variations
to verify adequate control by the Control Room with emphasis on how temporary variations are controlled in work packages.
A review was previously initiated to address the adequacy of
critiques.
The panel concluded that it was necessary to expe-dite this review.
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Examine current, site corrective action systems to 'see'what im-
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provements can be made.- There appears to beLa stigma associated with~using Quality Deficiency Reports.
The panel concluded that-it was necessary to improve. site corrective action systems.
Review the~ work control. system. The panel concluded that this-
-job order package was confusing and that information was lost or
not documented from one revision to the next.
NRC team inspec--
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tion 50-219/88-203 had previously identified weaknesses inlthe
' Job OrJer revision process.
Perform a detailed. review -of.the conduct of the original cri-
tique.
At the end. of this report period, the panel was still developing a.
L schedule for implementation cf the proposed corrective actions.
3.2 Reverse Direction Testing of. Containment Isolation Valves. (92701, 71707)
NRC Inspection Report 50-219/86-27 documented 13 containment isola-tien valves where the' licensee performed Type C leak testing in the reverse direction.. Appendix J of 10 CFR.50. allows Type C leak test-ing of valves in the reverse direction provided.that documentation shows the results' to be equivalent or more conservative..Although this documentation was not available during the 1986 inspection, the licensee stated that reverse direction testing of these valve provide equivalent or more' conservative results.
The inspector documented this " issue as an unresolved item (50-219/86-27-01) pending NRC review of the licensee's documentation.
During this inspection period, the inspector reviewed the justifica-tion for reverse direction testing tht 13 containment isolation valves. A memorandum from Technical Functions, dated February 25, 1987, documented the justification for this testing.
Seven of the 13 containment isolation valves were air operated butterfly valves and were evaluated as having identical flow and seating characteristics in either direction.
The memorandum stated that reverse direction testing of these seven valves was as conservative as testing the valves in the same direction of flow.- The remaining six valves were 2-inch globe valves (Black Sivalls & Bryson Inc., Model 70-14-2R).
The conclusion from the memorandum stated that reverse direction testing was more conservative because the test pressure.was directed over the seat and therefore, the. pressure will assist valve closure and decrease leakage. The inspector disagreed that this testing would be more conservative, and requested additional information on the leak testing of these valves. The licensee stated they were aware of weaknesses in the 1987 evaluation, and reevaluated the leak
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. testing of all-13 valves in February 1989. Plant Engineering con-cluded the reverse direction-leak testing of four containment isola-tion ' valves was not conservative-and not in: compliance with the re-
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quirements of Appendix J.
Evaluations are still in progress to de-termine a resolution to adequately test these, valves.
'During. review of-the licensee's reevaluation, the inspector ques-tioned the implementation of corrective action systems. Although
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Plant' Engineering had ~taken measures to identify anc rtsolve the nonconformance, the licensee had not written a deviation report, im-plement0d their corrective action systems nor evaluated this issue?
for deportability.
3.3 - NRC Conclusions -
In th'e first event-the licensee failed to address the entire scope of the pinning of reactor coolant pressure boundary hangers, and thus f ailed to correct this condition adverse to quality.
This failure was demonstrated on 5/9/89 when two additional pinned hangers were identified. The safety significance of fixing pipe ~ support spring cans in place, is a possibility, during plant heatup and cooldown, 'to overstress the systein piping.
The primary system piping constitutes one of' the barriers which prevents the uncontrolled release of radio-active material. The licensee's analysis concluded in both cases, howeser, that' excessive stresses were not imposed on-system piping.
In the second event, established measures did not promptly identify and correct nonconservative containment. isolation valve leak rate testing. The safety.~ significance is that actual containment leakage in an accident would have been greater than the predicted leakage.
The NRC's requirements, as specified in 10 CFR 50, Appendix B, and the licensee's requirements, as'specified in their Operational Qual-
.ity Assurance program, require that measures be established to promptly identify and correct conditions adverse to quality. For significant conditions adverse to quality, steps to prevent recur-rence shall be taken.
These events constitute a violation of NRC requirements in that the licensee's established measures did not identify arc correct these conditions adverse to quality, and steps were not taken to prevent recurrence (50-219/89-12-01).
These events are significant because they highlight weaknesses in licensee established measures to identify and correct conditions ad-verse to quality and implement actions to prevent recurrence.
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4,0 Plant Suram With Reactor Isolation (71707, 93702)
4.1 Event Description On May 18, 1989 the plant experienced a trip and a reactor isolation.
Instrumentation and Control technicians were performing a calibration at the generator load recorder. As part of this calibration the technician lifted a lead which caused a loss of generator reactive load indication. The control room operator responded to the lost indication by manually increasing the excitation of the generator.
He did not realize at this poi-t that the loss of reactive load in-dication was caused by the 1, ed lead. The result of increasi ;
generator excitation in this configuration was to over excite the generator. The plant is designed to open the generator output breakers when the generated is over excited.
This load reject was sensed by the turbine acceleration relay and generated a reactor scram signal.
Plant electrical loads did not automatically transfer to the startup transformers resulting in a loss of power to plant electrical buses.
Wnen the reator scrammed, the operator noted that feedwater had been lost and that reactor water level was decreasing rapidly.
He re-sponded to these indications by closing the main steam isolation vahes (MSIV). As a result of the turbine load reject and the fast closure of the turbine control valves, reactor pressure increased rapidly and initiated both isolation condensers, tripped all reactor recirculation pumps and opened two electromatic relief valves (EMRV).
When reactor pressure started decreasing, the EMRVs closed. Because of the loss of power to the plant electrical buses, both diesel gene-rators automatically started and powered the respective safety buses.
Plant operators took prompt actions to stabilize plant conditions.
Plant nonsafety electrical loads were transferred to startup trans-formers about 15 seconds after the trip. Operators started the feed pump and restored feedwater flow to the reactor in about 15 minutes.
Reactor pressure was being controlled using isolation condensers, and the reactor water inventory was essentially constant.
Reactor water level indication rose with decreasing reactur pressure and fell with increasing reactor pressure. Af ter the feed system was returned to service, water level was gradually restored to normal.
Plant safety loads were transferred to the startup transformers; and, the emer-gency diesels were secured.
A controlled plant cocidown was started using isolation condensers.
It was necessary to place the plant in cold shutdown in order to restart the reactor recirculation pumps.
The plant was cooled down using the isolation condensers.
The shut-down cooling system was placed in operation.
Since there are no jet pumps at Oyster Creek, the reactor recirculation pump discharge and suction valves must remain open to maintain communication between the
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- core and the vessel downcomer regions.
In order to achieve this com-munication and avoid the possibility of short circuiting shutdown cooling flow when reactor recirculation pumps are not running, the reactor water level was raised to 185 inches as required by licen-see's procedures.
The isolation condenser steam inlet valves were closed to avoid the high water level flooding the isolation condenser steam lines which could cause water hammer upon system initiation.
As the plant neared cold shutdown, noncondensible gases came out of solution as indicated by a positive reactor pressure while reactor temperature was well below 212 degrees.
The licensee drained the main steam lines and vented these noncondensibles from the reactor vessel. At 11:22 p.m. a reactor recirculation pump was started, and the plant was in cold shutdown.
4.2 Inspection Review of the Event Resident and regional NRC inst.-ctors reviewed the circumstances leading to this trip, operator response, plant response and the lic-ensee corrective actions.
Events that Led to the Trip The Instrument and Control technicians were performing a calibration of the generator load recorder using a plant procedure which gives general guidance on calibration of installed plant instrumentation.
The technicians discussed the performance of this calibration with the control room operator (CRO) and the group shift supervisor (GSS)
approximately an hour and a half before beginning the evolution.
Proper authorization to begin work was obtained by the technicians.
During these discussions, however, the technicians did not indicate to the CR0 or the GSS that this work would require the lifting of an electrical lead or that generator reactive load indication would be lost. Also, the cover sheet for the short form of the job order in-dicated that a temporary variation was not required.
Station Procedure 105, " Control of Maintenance," requires procedures or plans to clearly identify how and under what conditions intercon-necting systems or equipment can or will be operated or otherwise affected.
This identification was not performed.
The lack of under-standing by the technicians of the exact scope of work required re-sulted in a failure to research what the exact effects on plant operation would be.
The consequences were that neither the GSS nor the CR0 understood that a lead would be lifted or that generator reactive load indication would be lost.
This event was compounded by the hour and a half which elapsed before the technicians actually began work.
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The licensee's review of the maintenance control came to the follow-ing conclusions:
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The effects of the recorder calibration on 'the plant were not
reviewed thoroughly prior to the start of the work.
This calibration was not included in th'e' shift briefirig.
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Nothing in the work package indicated that a lead was to be-
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lifted.
A detailed prejob briefing was not conducted.
- The start of the work was delayed by approximately an hour and a
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half after authorization to begin work.
.Neither the control room operator nor the group shift supervisor.
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was notified immediately prior to lifting the lead.
To address these items the licensee plans the following actions:
Station Procedure 108, " Equipment Control," was revised to de-
L lete the provision that temporary variations could be controlled under job orders.
Requirements were added to enhance'the com-
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munications between the work group and the control room speci-fically notifying.the control room. operators immediately before implementing and immediately af ter removing a temporary vari-ation.
- Maintenance and Construction Facilities Procedure A100-ADM-3660.01,." Conduct of Installed Instrument Surveillance, Cali-bration and Maintenance," was enhanced to incorporate additional equipment control requirements of Station Procedure 108 and Station Procedure 105.
Station Procedure 105, " Control of Maintenance," was changed to
require enhanced communication between the work group and the control room.
The required documentation for temporary variations will be pro-
vided to the control room as specified in Procedure 108 and kept on file until the temporary variation is removed. A review of preventive and repetitive maintenance calibration items was con-ducted to identify those which currently require temporary vari-ations. The additional requirements identified above will be imposed for performance of these items. A review of generic job
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orders and preventive maintenance items was conducted.to iden-tify whether or not these correctly. identified the' need _for tem-
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porary variation.
Maintenance work on critical plant' circuitry _in the future wil'1
be-performed by qualified "A" maintenance personnel.
Conference Call On May 20, 1989, a conference call was held between the licensee and the NRC to inform regional management of the results of the licen-see's review and of the licensee's corrective actions.
Three speci-fic areas were discussed: (1) the plant response to the over excita-tion of the main. generator, (2) the effects of the overvoltage con-dition on. plant electrical equipment and _ instrumentation, and (3) the operations and maintenance interactions which led to this event.
The licensee stated that a Post Trip Review Group (PTRG) was convened to review this event. The PTRG concluded that the plant had re-sponded as designed when the 4160 volt buses are not automatically energi ed from offsite power during the over-excitation trip._ Licen-see evaluation concluded that there were no detrimental effects on.
electrical equipment and instrumentation from the overvoltage con-dition.
A maintenance critique determined that the root cause of this event was poor planning and communications.
Long term correc-ti.ve actions include: (1) evaluating the feasibility. of modifying.the.
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plant such that the startup transformers will automatically energize the 4160 volt buses when the-auxiliary breakers trip, (2) reviewing how maintenance activities are conducted, (3) evaluating the need for increasing the buffer ~ capacity of the event log, and (4) evaluating the need for the standardizing of reference times for all computer files.
The inspector had no further questions about the licensee's correc-tive actions in the area of maintenance control.
4.3 Electrical Plant Design The main generator protective logic was reviewed by an NRC inspectar to ascertain whether the station's electrical system responded to the plant transient as designe.. This evaluation consisted of review of elementary drawings, FSAR, and interview 5 with GPU engineering per-sonnel.
Observations and results of this review are described below.
4.3.1 Overvoltage of 4.16KV Buses Prior to the plant transient, the station auxiliary trans-formers were providing the source of power to the non-1E (IA, IB) and IE (IC, ID) 4.16KV buses. The operator ac-tion, increasing the generator excitation, resulted in an
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L increase in the 4.16KV' bus voltage. During this overvolt-L age condition the IA~ and IB bus overvoltage. relays. alarmed at approximately 4410 volts.
Subsequently,'one main; gene-rator overexcitation relay tripped at.a setpoint corres-ponding to approximately 4548 volts (on the 1A/IB buses)
following a 45.second delay. A second generator overexci-
.tation' relay setpoint corresponding.to approximately 4857-volts did not trip.
It was concluded that the 4.16KV buses-
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were in an overvoltage condition between-4548 and 4857 volts. This overvoltage condition was present.until the l -
overexcitation relay tripped. The'4.16KV b'us voltage de-E creased upon plant trip.
The bus undervoltage relays
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tripped and the emergency diesel generators started to supply emergency power to the buses.
The licensee initiated an engineering evaluation to deter-mine the effect of overvoltage on various plant equipment and instruments.
From review of the relays which tripped it was determined that the maximum voltage the equipment
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could have been subjected to,was approximately 4857 volts-or.117% of normal voltage at the 4.16KV buses. The licen-see consulted with equipment manufacturers to determine any possible damage to equipment due to high operating volt-ages. : This evaluation included equipment and instruments such as motors, battery chargers, solenoids-and relays.
Due to equipment supply voltage tolerances and the rela-tively short time the high voltage condition existed at equipment, the licensee concluded that the overvoltage con-dition was not detrimental to equipment operability.
No unacceptable conditions were identified.
4.3.2 Loss of Power to the 4.16KV Buses Generator protective relays are installed to monitor selected plant conditions and to provide inputs to the generator master and backup lockout relays 86G and 86GB, respectively. A trip of either lockout relay initiates
protective actions to completely isolate the main genera-
tor. One such protective action is to trip the normal feed breakers IA and IB to prevent backfeeding of power from the
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plant 4.16KV buses to the main generator.
The tripping of breakers IA and IB initiates an automatic closure of breakers SIA and SIB which powers the-4.16KV buses via the startup transformers.
During this transient the generator overexcitation resulted in tripping of the main output breakers GC1 and GDI.
However, it did not result in the tripping of the master or backup lockout relay since these relays are only actuated in response to tripping of gene-rator protective relays.
This original plant design was
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tions without much delay except when protective relays were actuated to protect the main generator.
Since the lockout relays-did not trip, an automatic transfer from the station auxiliary transformer to the startup transformers was not initiated This condition resulted in the 4.16KV buses being without a source of power since they were still con-nected to the main generator through the station auxiliary transformers.
Subsequently the 4.16KV IC and ID bus under-voltage relays tripped, resJ1 ting in the emergency diesel generatore starting and powering respective emergency loads.
-The non-1E buses were subsequently powered by the startup transformers once the operator initiated a transfer from the station auxiliary transformers.
The licensee has initiated an engineering evaluation to determine the need for plant modifications so that the main generator lockout relays would also trip in response to plant conditions other than those included in the current system design. These possible modifications would result in the automatic transfer of power to the 4.16KV buses to avoid requiring the emergency diesel generators to start and power the buses.
Results of NRC review indicate that the plant's electrical systems resptnded as designed. The protective action to trip the main.utput breakers and the field breaker discon-nected the generator from an overexcitation condition. The response of the emergency diesel generators to the 4.16KV bus undervoltage condition was as designed.
The actuation of the emergency diesel generators was a direct response to the lack of an automatic transfer of power to the 4.16KV during to the plant transient. Though the plant "esponded as designed, it nevertheless resulted in a momentary loss of power to the IE buses and unnecessary challenge to the emergency system.
This design is currently being reviewed by the licensee to determine if modifications are desir-able.
The inspector had no further questions in regard to plant electrical design.
4.4 Overall P! ant Response Inspectors reviewed the plant's automatic response to the trip.
The plant trip was initiated when the turbine generator was unloaded due to opening of the generator output breakers.
This unloading cor-rectly initiated a reactor scram and also a fast closure of the tur-bine control valves.
Reactor pressure increased as the control
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In addition, the anticipated transient without scram (ATWS). trip set point was exceeded, causing a trip of all five reactor recirculation pumps.
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Plant Emergency Operating Procedure under RPV Water Level Control l
requires that the operators manually open control rod drive hydraulic valve, V-15-30. When the operators attempted open the valve they
- discovered that the valve hand wheel interferred with an adjacent valve. This interference precluded the operators from fully opening
.the valve.
In response to this problem the licensee subsequently-removed the hand wheel and installed a racketing mechanism to allow full valve operation.
As a result of the overvoltage condition on plant buses, plant safety valve and.electromatic relief' valve acoustic position indication'was lost on several valves. 'This caused the indication' to fail, indi-cating'that the relief valves were open. Operators responded by verifying that the valves were closed, using backup position indica-tion. This problem was enrrected by~ resetting the power supply to the acoustic monitor.
0verall, the inspector concluded that required automatic safety fea-tures initiated as designed.
The inspector had no further questions
'in the area.of plant equipment - response.
4.5 Review of Operator Response The inspector reviewed the control room operator's response to the loss of generator reactive load indication. When the operator ob-
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served that the reactive load was indicating zero, manual action was taken to increase generator excitation. This action resulted in an increase of generator output vcitage and plant bus voltage.
Operator response to this indication was not appropriate since he focused solely on the reactive load indication.
He neither crosschecked this indication with related plant parameters nor fully realized the ef-fects of continuously increasing the generator excitation.
It was the over excitation trip of the generator which actually initiated the plant transient. Also, while the operator was manually control-ling generator excitation, he did not realize the full significance of the generator over excitation alarm.
Because of these weaknesses, the licensee briefed control room opera-
'i tors on operator response to the loss of generator reactive load.
Specifically, control room operators were reminded of the need to verify plant indications prior to taking corrective action.
Also operators were reminded of the exact configuration of the generator over excitation trip.
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After the reactor scram signal was received,- the operator responded L
' promptly and correctly to stabilize plant conditions. The operator recognized the lo:;s of feedwater and-closed the main steam. isolation
- valves. This action served to. conserve reactor water inventory.
-The licensee identified a weakness in the initial response of the operators to reactor' pressure control in that after the isolation condensers automatically. initiated, they were left in operation.too.
long resulting'in a pressure reduction-to approximately 600 psi..
This weakness was identified by the Plant Operations Director.
Sub-sequently,'the operators controlled reactor pressure more closely.
In cooling down the plant on the isolation condenser, the control room operators correctly recognized the need to raise reactor water level' to 185 inches in order to ensure effective shutdown cooling.
Some difficulty was encountered because of the noncondensible gase.s which left solution, resulting in a reactor pressure of approximately--
50 lbs. while the ' reactor coolant temperature indicated well below 212~ degrees. The control room operator'took appropriate action to vent the reactor pressure-vessel.
Once this was accomplished a reat-
. tor. recirculation pump was ' started, re' storing forced circulation to the core,.and the plant.was in cold shutdown.
Except for the initial operator response to.the loss' of generator.
reactive load indication, control room operators responded promp.tly and correctly to stabilize plant conditions and to cool down the plant using isolation condensers.
The inspector had no other questions in the area of control room operator response.
4.6 Post-Trip Review Group Reports The inspector reviewed the post trip review report and also the in-dependent post trip review group (PTRG) report concerning this transient.
The PTRG and the independent PTRG performed a. thorough and effective evaluation in identifying actual plant response and
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also in identifying remedial actions which were necessary prior to returning the plant to operation.
The inspector had no questions in
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this area.
Overall, the licensee responded promptly and effectively in dealing with this transient. A plant trip with a reactor isolation is one of the most significant transients that the plant can experience.
The control room operators responded appropriately, and the plant tech-nical support staff responded effectively to identify and correct-adverse conditions prior to returning the plant to operation.
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5.0 Core Spray Net Positive Suction Head (71707)
On 5/22/89 = the. inspector met with licensee personnel to discuss core spray.
system net positive suction head. During the design' basis accident, water will be retained.-in the oottom of the drywell resulting in a drawdown-of-the suppression pool.'The inspector asked the licensee if this drawdown effect was considered in core spray system net positive suction head cal-culations.
Th'e licensee's review concluded the water retained in the bottom of the
'drywell was not considered in core spray system net positive-suction head (NPSH) calculations, :The licensee's latest review indicated'there would be a drawdown of approximately 5 inches in the torus water level. and there would be approximately a 1 degree-increase in peak containment. tempera-ture.
The NPSH~available to core spray pumps A, B and D exceeded the NPSH required.
For core spray pump C, the calculations indicaud the available NPSH was less than required.. Assuming a pump runout of 5,000 gpm and no overpressure in the torus, the licensee calculated the required NPSH was 20 ft. and the available was 19.6 ft.
If an assumed runout flow of-4,900 gallons per minute is used, the required NPSH is 19.5 ft. and the avail-able NPSH.is 20.2 ft.
The licensee concluded these conditions were ac-ceptable based on:
The conservatism which were applied.in the calculations (no credit
was given for containment overpressure).
The loss of NPSH would not occur for several hours into the event at
which time'it would be acceptable to remove core spray pumps from service.
Even if the pump loses NPSH, the pump will not catastrophically fail.
- NPSH after the peak containment temperature will be recovered as the
torus'is cooled.
The inspector concluded that the consideration of the water retained in the drywell reduced the margin of NPSH to core spray pumps.
Also, under worst case condition, the NPSH for core spray pump C is marginal.
6.0 Surveillance Observation (61726)
On 6/1/89 inspectors observed the performance of surveillance test 604.4.003, " Reactor Building to Suppression Chamber Self Actuating Vacuum Breaker Surveillance Test and IST".
The inspector verified that the cur-rent revision of the surveillance test was used, the proper authorization to perform the test was obtained, and that the operators had a copy of the test in hand during test performance.
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.The inspectorireview'_found -two minor deficiencies.
First, step 6.3 of'the-procedure specified-that a cross bar be inserted through. holes drilled in the vacuum breaker valve weight levers.
The actual plant configuration is -
that.there are multiple holes which ~could be used, and the surveillance-test did not: clearly specify which'ones were correct'. The equipment
- operator _ used.the inner most set of' holes which would result in conser-
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vative readings. The second deficiency 'Is that step 6.6 of the' test-
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specified: opening the valve to the full open position using the spring-n l
' scale.
Because of the physical configuration of the piping this was not
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possible.
The inspector discussed'these' discrepancies with the operators
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and.with the. group _ shift. supervisor.
Procedural changes were initiated to
correct-these discrepancies, and.the inspector reviewed these changes.
The inspector-had no other questions in regard to the pe,-formance of this surveillance.
7. 0 Local Power Range Monitors' (LpRM)-(62703)
The inspector observed the insertion of currents into the local power-range monitor (LPRM)- flux amplifiers.
This evolution was performed in accordance with Appendix C of Procedure 2001.39, "LPRM Calibration Using-PSMS" and provides a means to insure that during power operation the Emeasured power distribution is accurately determined. No unacceptable conditions were noted.
THE REMAINDER OF THIS PAGE IS INTENTIONALLY l
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8,0 Security Event (71707)
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THESE PARAGRAPHS CONTAIN SAFEGUARDS INFORMATION AND ARE NOT FOR PUBLIC DISCLOSURE. THEY ARE INTENTIONALLY LEFT BLANK.
l The Ovster Creek Security Plan requires personnel be assigned to monitor vital areas as a result of intrusion alarm malfunction. This event, failure to provide monitoring of a vital barrier door for over four hours, is a violation.
A Notice of Violation will not be issued because this event was identified by the licensee; it fits in Severity Level IV; it was reported in the required time frame; immediate and long term corrective actions, including measures to prevent recurrence, are or will be implemented; and, it was not a violation that could reasonably be expected to have been prevented by corrective action for a previous violation.(50-219/89-12-02).
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n 9.0 ' Review of-previously Open Inspection Fidinas (92701, 92702, 25576)
-(Closed) Inspector Follow Item 85-BU-01.. IE bulletin 85-01, Steam Binding of Auxiliary Feedwater Pumps, informed licensees of a potentially se'rious safety problem involving the inoperability of auxiliary feedwater' (AFW)
pumps as a Result of steam binding. 'IE Bulletin 85-01 is' applicable to Pressurized Water Reactor (PWR) plants only, and a response by the licen-see is not required. This item is administratively closed.
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(Closed) Inspector Follow Item 85-SB-01'.
Information Notice (IN) 84-52, Inadequate Material Procurement Controls on the Part of Licensees and Ven-dors, provides additional information to licensees on hardware problems and deficient procurement controls and quality assurance (QA) practices.
Two vendors were identified in the IN for supplying under size-(thin) wall piping. The licensee requested and received confirmation from their dis-
-tributors that the thin wall piping from those vendors was not obtained.
Additionally, seamless pipe in stock was checked, and the receiving in-spection plans for piping / pipe spools were revised. This additional ac-tion'was reviewed i d verified by the inspector. This item is closed.
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(Closed) Inspector Follow Item 86-17-01.
This item was opened to follow licensee inspection plans to verify that contractor work on snubbers was satisfactory. The contractor in question had removed the weld lugs on snubbers to facilitate their removal and repair. When these snubbers were
. reinstalled,. the contractor failed to reweld the lugs on these snubbers.
The licensee has inspected all the snubber work performed by the contrac-
' tor, and the defects have been corrected.
Inspection of the remaining snubbers was performed through surveillance required by Technical'Speci-fication 4.5.
Existing procedures were reviewed regarding the control of contractors, and two new procedures'were developed for the Maintenance and Construction Facility (A000-ADM-7101.0) and Quality Assurance (6100-QAP-7207.02).
The inspector reviewed the corrective' actions taken and veri-fied that the new procedures were satisfacto'rily implemented. On site verification of the weld lugs was not performed because the snubbers in question were covered with pipe insulation.
This item is closed.
{_ Closed)InspectionFollowItem 86-21-02.
Post Accident Sampling System (PASS) hanger #PA-H5 appeared to be attached on a snubber strut. The lic-ensee investigated the concern and determined that the hanger #PA-H5 was welded to the reactor wall steel plate as indicated on the Burns and Roe Drawing H0240.
The hanger however, being directly aoove the snubber, did give the appearance that the hanger was attached to the snubber strut.
Since the hanger was inaccessible during this inspection, the licensee
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provided the inspector with a walk down report and drawings that show the I
PASS system hanger #PA-H5 was welded to the reactor wall steel plate.
This item is closed.
(Closed) Inspector Follow Item 86-21-03.
The licensee investigated the cause of the overheating and failure of a motor operator for Core Spray System valve V-20-27 during a routine surveillance test.
The licensee
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- determined that the cause of failure was " revised operating requirements above those for which the valve operator was origina'ly intended". When a suitable spring pack replacement for V-20-27 was ordered, the original equipment manufacturer (OEM) provided a lighter spring pack that was too weak to allow the new valve operator to function properly. The original operator with its heavier spring pack was reinstalled and the valve func-tioned properly.
The failed operator was sent to the manufacturer for evaluation and returned with a heavier spring.
To prevent recurrence, the licensee has revised its Operator Maintenance Electrical Procedure requir-ing that the data sheets include data regarding the rating of the new com-ponents, such as the torque switch blocking plate size.
Any deviations in the data from the acceptance criteria must be evaluated by Plant' Engineer-ing prior to placing the valve in operation.
This item is closed.
(Closed) Unresolved Item 86-27-01. This review is documented in paragraph 3.0 of this report. This item is closed.
(Closed) Unresolved Item 86-01-05: Environmental qualification of cable /
connector assembly for the containment high range radiation monitor.
The inspector reviewed the revised EQ File No. OC-373 containing the similar-ity analysis for the installed configuration and the test specimen. The licensee has selected an alternate configuration for the cable / connector assembly.
The Oyster Creek configuration replaces the BIW cable with a qualified Rocbestos cable (Reference 373-01 paragraph 4.9.5) attached to the Vendor Test Model 878-1 cable connector, and sealed by potting with Slyguard 186 compound as was done in the qualified test specimen (Refer-ence 373-06, Appendix A).
All possible leak paths have been sealed and cable wicking problems resolved. The installed configuration is consi-dered to be the qualified tested configuration.
This remaining item of 86-01-05 is technically closed.
(Closed) Unresolved Item 85-39-01: Adequacy of licensee's management con-trols over E0 program information and evaluation.
This item questioned the licensee's failure to make a 10 CFR 50.72 notification in regard to the environmental qualification of terminal blocks. Prior to the E0 Group completion and documentation of the terminal block evaluation, the licen-see had determined that the terminal block in question was a Stanwick, and qualified to perform the intended function in its environment.
As such, deportability under 10 CFR 50.72 was not considered. The licensee's posi-tion regarding potential EQ deficiencies is that they must be reviewed in a reasonable and timely fashion.
Upon determination that the EQ defi-ciency exists, the item will be repaired or an operational evaluation will be performed.
Plant Procedure 105.3, " Maintenance of EO Equipment," has been revised and the internal reporting requirements clarified. This item is closed.
(Closed) Unresolved Item 85-39-02: Qualification status of the Stanwick terminal blocks for use at the Oyster Creek site.
The licensee determined that the Stanwick terminal block was qualified.
EQ File No. OC-389 con-tains the supporting documentation that demonstrates environmental quali-fication of the Stanwick Terminal Block in accordance with 10 CFR 50.t9
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. requirements. ' An NRC EQ team inspection at Oyster Creek March'.24-27, 1986,. (IE Report-50-219/86-08) reviewed the Stanwick EQ File No. OC-389, arriving at the same conclusion.
This item is closed.
L (Closed) Violation No. 85-39-03: ' Licensee's f ailure to identify elec--
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trical equipment important to. safety and preparing a record of oualifi-cation, GPUN letter to.the NRC, dated November 26, 1985, provided the methodology used for plant walkdowns, in support of the EQ Master List,-
that were conducted in the 1984-1985 time frame and during the cycle.10M outage. The' licensee had made a conscious decision, from a safety stand-point,.not to open or disassemble equipment to establish this baseline.
Upon discovery of the Stanwick terminal block, the licensee readily deter-
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mined the, block to be qualifiable. An EQ File No. OC-389 was established l-for the Stanwick terminal blocks containing supporting documentation to L
demonstrate environmental qualification.
The licensee has since (February 10,1989) deleted the Pressure Switches R23A, B, C and D, which used the Stanwick terminal blocks, from the EQ Master List per EQML deletion OC-105 via DRF-080917.
This item is tech-
-nically closed.
l-(Closed) Unresolved Item 86-08-05: Failute to address functional per-
. formance requirements in EQ File No. OC-312, OC-388 and DC-326.
EQ File
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l Nm OC-388 was completely revised in November 1986 to delete:all refer-I ences to instrument tape splices replaced during the cycle 11R outage.
L This file now only addresses.the GE installed motor tape spices for the
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containment / core pump motors.
The EQ File OC-326 discussion of low IR readings on instrumentation circuits has been revised.
New calculations i
(TDR-904) have been generated to determine loop accuracies which will be l-included.for each instrument circuit.
Document Release Form (DRF) 062655 dated-February 12, 1938, documents the revised loop' accuracy calculations and file applicability.
EQ File No. OC-312 (Rockbestos Cable) has been completely revised and reformatted for auditability and to improve clarity of information within the. document.
Functional performance, measured parameters, similarity and other component qualification characteristics are addressed within the EQ file.
This item is closed.
(Closed) Unresolved Item 86-08-04: Licensee's failure to adequately demonstrate equipment operability with switch (NAMCO) in:ernals exposed to
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harsh environment..EQ File No. OC-319 (NAMCO Limit Swit:nes) is being revised and reformatted for auditability and clarity of information con-tained within the document.
The revision includes documentation informa-tion from the vendor which discusses the differences bet-een the installed configuration and the test specimen.
This difference, a change in the-torsion spring has no effect on the environmental qualification of the component. Conduit seals have been installed in all but two of the NAMCO limit switches (V-6-395).
These switches are in a mild environment and do not require sealing. This issue was discussed in detail during October 20, 1988, Enforcement Conference.
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L (Closed) Unresolved Item 88-16-01: Auditability of the EQ Files, deletion of RE-023 switches from the EQ Master List and requirements for low main steam line pressure isolatio_n.
The licensee is in the process of revising and reformatting all of the EQ files to improve auditability and clarity of information contained within the file. The licensee has completed revi-sion of approximately 80*; of the EQ files, with the remainder scheduled for completion by December 1989. The inspector noted the improvement in EQ File auditability and ease in locating applicable qualification data.
The licensee preliminary conclusion that for a line break equal to an open bypass valve, the RE-023 switch setpoint would not be reached was con-firmed by calculation No. C1302-411-5450-027. The RE-023 switch has since been deleted from the EQ Master List (deletion No. OC-105) and the FSAR has been revised (TR-AT5505) to reflect the removal. This item is closed.
10.0 Review of Periodic and Special Reports (71707)
Upon receipt, periodic and special reports submitted by the licensee were examined by the inspectors.
The inspectors also reviewed weekly reports when received.
These reviews included the following considerations: that the report includes the required information, that the planned corrective actions are adequate for resolution of identified problems, and that the reported information is valid.
No unacceptable conditions were identified.
11.0 Radiation Protection (71707)
During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosime-try, personnel and materials leaving were properly monitored for radio-active contamination, and monitoring instruments were functional and in calibration.
Posted extended Radiation Work permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate.
The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the area.
No unacceptable condi-tions were identified.
12.0 Inspection Hours Summary (71707)
Inspection consisted of 209 direct inspection hours.
43 of these direct inspection hours were performed during backshif t periods, and 11 of these hours were deep backshift inspection.
13.0 Exit Interview j
A summary of the results of the inspection activities performed during
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this report period were presented at a meeting with senior licensee man-
agement after this inspection. The licensee stated that, of the subjects
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discussed at the exit interview, no proprietary information was included.
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