IR 05000219/1989007
| ML20247J879 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 05/17/1989 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247J867 | List: |
| References | |
| 50-219-89-07, 50-219-89-7, IEB-88-007, IEB-88-7, NUDOCS 8906010154 | |
| Download: ML20247J879 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
Report No.
50-219/89-07 Docket No.
50-219 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:
February 26 - April 1, 1989 Participating Inspectors:
S. Barr W. Baunack E. Collins T. Eas11ck T. Fish D. Lew K. Kolaczyk Approved By:
O d5dh 6/o[#
C. Cowg611, Q f, Reactor Projects Section 1A Date Inspection Summary: Inspection February 26 - April 1, 1989 (Report No. 50-219/89-07)
Areas Inspected: Routine inspections by resident and region-based inspectors (410 hours0.00475 days <br />0.114 hours <br />6.779101e-4 weeks <br />1.56005e-4 months <br />) of activities in progress at the completion of the outage, in pre-paration for startup, and plant startup activities. These inspections included independent valve position verification, surveillance observations, maintenance observations, procedure reviews, event followup, control room observations and facility tours.
The inspectors observed the loss of offsite power test, shut-down margin test, scram time test and containment integrated leak rate test.
Inspectors reviewed licensee corrective actions in regard to preliminary safety concerns, Appendix R concerns and core spray relief valve problems.
Region-based inspectors reviewed the licensee's operator training program including plant modification training, program documentation, and licensee response to Bulletin 88-07.
Licensee corrective action was reviewed on three previous in-spection findings.
Results: The inspectors concluded that the licensee conducted a controlled, organized startup which was closely monitored by plant management personnel.
There were, however, a number of plant materiel problems that became evident during the phnt startup. The most significant of these problems was the high vibration on the D reactor recirculation pump. The licensee action to shut
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down the plant to repair the recirculation pump was prudent.
In regard to the Preliminary Safety Concern process, licensee review of previously closed items reestablished confidence that the process had not left significant safety issues unresolved.
In the area of training the inspectors concluded that out-age modification training was satisfactory and that the licensee training pro-gram and the documentation of that program were satisfactory.
Licensee imple-l mentation of NRC Bulletin 88-07 requirements was evaluated as satisfactory but
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remains open pending licensee review and incorporation of LPRM indications to i
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aid in detection of power oscillations. Three previous inspection findings were closed. No violations or unresolved items were identified.
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TABLE OF CONTENTS PAGE~
1.0 Background...........................................................
-2.0 Augmented SiteLInspection Activities.................................
I 2.1 Plznt Operations..................................................
1-2.2 Plant Startup..................................................
2.3 -Control Room Observations.......................................
E 2.4 Maintenance.....................................................
~7 2.5 Surve111ance...........................-.........................
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2.5.1 Appendix K............................................
2.5.2 Plant Loss of Power Survei11ance......................
2.5.3 Shutdown Margin Testing...............................
2.5.4 Other Tests 0bserved..................................
3.0 Scram Time. Testing...................................................
'4.0 Containment Integrated Leak Rate Testing.............................
-5.0 Containment Spray-Preliminary Safety Concerns........................
6.0 Licen see Preliminary - Safety Concerns Reviewed........................
7.0~ Appendix R Concerns...................................
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8.0 Core Spray Systems Relief Va1ves.....................................
9.0 Training Review......................................................
-17 9.1 Plant Modification Training.....................................
9.2 Licensed Operator Training Program.........................
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i 9. 3. Li cen sed Operator Intervi ews....................................
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10.0 (0 pen) NRC Bulleti n 88-07 and Supplement I...........................
4 11.0 Air Operated Valves in Standby Gas Treatment System (SGTS)...........
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12.0 Licensee Action on Previous Inspection Findings......................
13.0 Backshift Inspections................................................
14.0 Exit Interview.......................................................
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i DETAILS 1.0 Background On September 30, 1988, the plant was shutdown due to problems experienced with the isolation condensers.
Since a refueling outage had been sched-
uled to begin on October 15, 1988, it was decided to begin the refueling l
at that time.
The refueling outage had a planned duration of 87 days and was scheduled to end on January 6, 1989.
For various reasons, including increasing the scope of the outage, the startup was delayed until March 26, 1989.
2.0 Augmented Site Inspection Activities Augmented Site Inspection was conducted to verify startup preparations had been properly completed, operators had been trained on outage modifica-tions, surveillance have been completed, maintenance is controlled and that Plant Operations conducted a controlled, safe, and orderly startup.
The Augmented Site Inspection independently verified selected system line-ups prior to startup and was intended to cover two shifts per day during startup beginning on March 20, 1989.
Because of delays during startup preparation and equipment malfunctions, the actual plant startup was not conducted until March 26, 1989.
The plant was again shutdown on March 28, 1989 because of a recirculation pump problem.
Areas inspected during this period included licensee records, maintenance activities, surveillance, performance of personnel, facility tours, and observations of Control Room activities.
Several events associated with routine operations which occurred were also reviewed.
The inspection findings are discussed in the following paragraphs.
2.1 Plant Operations (71707, 93702)
Various aspects of plant operations were monitored throughout the inspection period. The following findings were identified:
Plant startup which had been predicted to occur during early
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March was delayed for several weeks because of difficulties en-countered during the performance of maintenance and testing which had to be completed prior to reactor startup.
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The inspectors reviewed the most recent inservice test (IST)
results for the 52C and 52D emergency service water pumps. Both pumps are operating in accordance with requirements. Since both pumps just recently had new baseline data established, IbT data could not be compared.
No unacceptable conditions were iden-tified, i
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During the inspection period the auxiliary reactor water cleanup pump was undergoing repairs. This posed some difficulty for plant operation during the Containment Integrated Leak Rate Test (CILRT) and also the reactor cooldown following plant startup.
Without the auxiliary reactor water cleanup ~ pump, the only means available for water letdown from the reactor is by gravity.
To overcome this during the CILRT, a temporary connection from the condensate transfer system was installed to minimize makeup to the reactor. The reactor cooldown was delayed approximately one day while waiting for the pump to be returned to service. When it was determined that the pump could not be returned to service quickly, the cooldown was conducted using gravity letdown.
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Inspectors observed the plant cooldown using gravity letdown for reactor water level control.
Letdown flow was steady, and the control room operator closely and effectively performed the evolutions.
No unacceptable conditions were identifiad.
During March 6, 7, 8, and 9, inspectors performed independent
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valve position verifications on the core spray system I and II, instrument panels RK01 and RK02, emergency condensers A and B, standby liquid control, and emergency diesel generators 1 and 2.
All valves were found to be correctly positioned in accordance with licensee's approved procedures. A number of minor defi-ciencies, such as valves with no ID tags, valves with wrong location on lineup sheet, and valves with incorrect nomenclature for ID location were identified.
Licensee representatives re-corded all deficiencies noted and provided them to the Manager, Plant Operations.
The licensee has initiated a valve labeling program, which is in the early stage of implementation. The inspector had no further questions regarding this matter.
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As a result of the natural circulation steaming phenomena that occurred during the 11R operating cycle in the isolation con-densers, the licensee committed to a series of procedure and hardware improvements. These improvements were designed to pre-clude the occurrence of natural circulation steaming in the isolation condensers and provide troubleshooting actions to take if natural circulation does occur.
The improvements consisted of establishing time limits on the length of time that an isola-tion condenser could be left in a fully isolated condition, modifying the isolation condenser warmup procedure and additig thermocouple downstream of the isolation condenser vent valves.
The inspector verified that the Oyster Creek isolation condenser operating and troubleshooting procedures were revised to include the aforementioned commitments. No unacceptable conditions were identified.
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i Several additional issues associated with the isolation conden-sers which were identified in Inspection Report 50-219/88-80 have also been addressed..The licensee was to identify the de-sign basis for the isolation condenser steam inlet thermocouple placement-and also the basis for the alarm setpoint.
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ginal _ intent of the thermocouple was to assist in identifying a l
tube or return valve leak by the indication of a high tempera-ture.
The thermocouple have not been effective in performing this function. The alarm will continue to-be bypassed. No new information other than what was described in Inspection Report 50-219/88-80 resulted from the design basis information pro-
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vided. The. inspectors had no further questions.
The licensee also reviewed the potential single failure of the isolation condenser vent line to evaluate adverse effects on the operation of both condensers.
Licensee analysis shows the isola-tion condensers will remain operable with the vent line iso-lated.
Consequently, the failure of the vent line is not a safety issue. The inspector had no furt.her questions regarding t
this matter.
To arrest corrosion of the Oyster Creek drywell, the licensee
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committed to provide a drywell cathodic protection system prior to startup from the 12R refueling outage.
The inspector re-viewed the Oyster Creek cathodic. protection startup test pro-cedure and verified that the system was tested. The inspector also reviewed a draft copy of the proposed cathodic protection operation manual and verified that appropriate instructions were provided which would enable operations to verify satisfactory system operation. No unacceptable conditions were identified.
The licensee maintains a restart certification book that veri-
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fies that all startup prerequisites, maintenance items, and sur-veillances have been completed. The inspectors verified on a sampling basis the completion of these certifications.
No un-acceptable conditions were identified.
Prior to plant startup, the inspectors reviewed the safety evalu-
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ations for all outstanding temporary variations. No deficien-cies were noted.
During the SSOMI inspection, it was identified that under cer-
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tain conditions an overload condition on a diesel generator could be experienced.
The licensee committed to revise Proce-dure 341, " Emergency Diesel Generator Operation," prior to startup, to include instructions to the operators for loading the diesel with discretionary loads. These instructions are provided to keep the diesel generator within its load limita-tions.
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Sections 2.2.4 and 2.2.5 were added to provide minimum and maxi-mum load restrictions for the DGs in different modes of opera-tion (e.g., " automatic parallel operation,").. Changes and addi-tions were made to Section 3.4 providing information on the automatic loading sequences for the DGs for different situations (e.g., loss of offsite power, loss of offsite power with a LOCA, loss of offsite power with one DG inoperable).
In addition,.
guidance was provided on the addition of subsequent loads after-the auto-sequence is completed (i.e., what loads and how many).
No unacceptable conditions were identified.
During the startup, a valve' lineup problem was identified in the
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air supply to the MSIVs. A contributing factor in not identify-ing.the problem during the performance of the valve lineup veri-fication was the method by which changes to drawings are issued.
As a followup to this event, instrument air system drawing
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BR2013, Sheet 4 of 5, Revision 26 was' reviewed.
For this draw-
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ing, the control room files contained the original unchanged
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drawing and three separate copies of the same drawing, each with.
a different change on it.
This required the drawing user to mentally incorporate all the changes into'a single package.
h' hen licensee management became aware of the problem, action was taken to alert the Technical Functions Group of the problem and to ask them to initiate action to improve the ability of the control room operator to use drawings. An operation's request.
was issued to Technical Functions in writing.
Depending on when full compliance with the operation's request is achieved, this type of prompt action by management to correct an identified problem should be beneficial in both improving operator atti-tudes and in preventing future errors. Dyster Creek drawing control problems are discussed in Inspection Report 50-219/
89-05.
While reviewing this drawing the inspector noted that during periods when a number of operating procedures are in use, there is no dedicated space in the control room for station personnel-to use drawings. The inspector had no further questions regard-ing the foregoing matters.
As a result of the MSIV air supply valve lineup problem identi-
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fied above, the licensee reviewed all drywell valve lineup check lists and all safety system valve lineup check lists against the'
P& ids to verify no other errors exist. Some valves on the dry-well equipment drain tank which are on the drawing were not on the valve checkoff list.
No safety related issues were identi-fied.
The inspectors concluded that the licensee's corrective actions were appropriate.
The licensee prepared a Power Ascension Plan which provided the
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timing for the restart activities from "startup" until the plant reached full power.
The plan detailed shift activities through
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'the 23 shifts following initial criticality. ' Equipment prob-lems, primarily the
"D" recirculation pump vibration, made use of this plan impractical'after the third shift. Activities were verified to be conducted in accordance with plant procedures.
-The inspectors verified pre-critical checkoffs and the prer:-uui-
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sites required by Startup Procedure 201 were completed.
Frequent tours of the facility were conducted. Areas toured
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included:
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Control Room
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Reactor Building
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Turbin.e Building
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Cable Spreading Room
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Battery Room
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Diesel Generator Building
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No unacceptable conditions were identified.
2.2 PlantStartup(71707,71711,71715)
A.' plant startup was conducted on March 26, 1989, and was followed by two training startups. A plant heatup was started at 11:05 a.m. on the 26th and a.drywell inspection performed with the reactor pressure at 1000 pounds.
During the drywell inspection, excessive leakage was noted from the "D" recirculation pump seal. A decision was made to continue with the power increase and place the turbine on the line for equipment testing prior to shutting down for repair _s.
The gene-rator was placed on the grid, the feed pumps and heater strings placed into service, and then the plant was shutdown. All rods were inserted and the' mode switch placed into refuel at.2:59 a.m. on March'
29, 1989.
Some of the events which occurred and observations made by the in-spect' ors during the startup were as follows:
During the process of raising condenser vacuum, delays were ex-
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perienced due to air ejector and condenser vacuum breaker dif-ficulties.
A turbine stop valve leak was identified.
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"A" battery grounds were identified.
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Problems were experienced with IRMs 11 and 18, and SRM 22.
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As a result of the seal leakage identified on the "D" recircu-
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lation pump, vibration readings were taken on the pump while it was operating.
These readings indicated a shaft vibration of approximately 48 mils. This vibration was considered to be ex-cessive and the pump was shutdown.
Following the pump shutdown, the discharge valve failed to close and the pump suction valve had to be closed to prevent backward rotation of the pump.
The shutting of the pump suction valve placed the plant in a Tech-nical Specification Action Statement and a shutdown was initi-ated.
Notifications required by this condition were made.
The pump discharge valve was subsequently closed and the shutdown terminated.
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Followic.g Electomatic Relief Valve (EMRF) testing, the "A" valve showed signs of leakage.
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A through wall leak was identified on the
"B" feedwater heater vent pipe.
Overall, the startup was conducted in an orderly fashion and in ac-i cordance with facility procedures. Approximately 40 deficiencies needing attention were identified by the licensee.
These ranged from relatively minor items, such as feed pump oil leak, to a recircula-l tion pump seal leak and high vibration which necessitated a plant shutdown. The inspectors noted this was relatively high number of problems given the extensive outage that had been completed.
2.3 Control Room Observations (71711, 71715)
Control room activities were frequently monitored to observe opera-tional activities during the report period.
Two shift coverage was provided, by the inspectors, during plant heatup and power changes.
l Specific activities monitored were as follows:
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Operators were noted to be attentive and responsive to plant parameters and conditions.
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A number of plant evolutions were not conducted in sequence with the Power Ascension Plan; however, they were properly authorized.
Operators were using and adhering to procedures.
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Operator logs were observed to be properly maintained and re-flected plant activities and status.
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Control room staffing which exceeded Technical Specification requirements was maintained.
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'. Adherence to Technical Specification Limiting Conditions for
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Operation was verified by observing control. room' indications-and reviewing log sheets.
Operations management was observed to be frequently present:in
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the control room and on site continuously.
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Several shift turnovers were observed.
Operators were noted to
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be thorough in walking through the console-and panels with their-reliefs. - Discussions of activities and plant status were
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thorough.
For the power ascension evolution, a special shift briefing was conducted for each-shift.
This was observed by inspectors.
During the observation of control room activities, no unsafe condi-tions were identified.
2.4 Maintenance (71707, 93702)
'During the inspection period, the progress of various maintenance-tasks was followed up during the Daily Plan of the Day meetings.
Additionally, the overall performance of maintenance activities were.
frequently' discussed with both operations and management personnel.
The following observations were made:
The inspectors reviewed in detail the licensee's' actions.related
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to the failure of the control rod drive pump motor, the root cause determination, the breaker overcurrent trip setpoint, and the motor megger history. -The inspectors concluded licensee actions were appropriate.
While filling and venting the reactor feedwater strings, a
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flange leak was discovered on'the "A" feedwater pump discharge check valve. The leak was attributed to a bad gasket which was replaced.
Subsequently, it was discovered that with condensate pump discharge pressure applied, the check valve would not open.
Maintenance personnel loosened the flange fasteners with conden-sate pressure applied and the valve disc became free. Upon re-torquing, normal valve operation was verified.
Following plant startup, the joint was again found to be leaking. Additional maintenance was planned.
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The licensee's actions to repair an air leak on main steam
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isolation valve NS03B were observed. The repair of the leak was delayed because of communications inadequacies between opera-
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L tions, who identified the leak, and maintenance, who was re-sponsible for repairing the leak.
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Maintenance activities delayed startup from March 20, 1989 until
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March 26, 1989.
During the startup, additional maintenance-items were noted.
Some of the~ activities which required mainten-ance attention during the period March 20 to March 28, 1989 were:
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"A" feedwater discharge check valve leak and subsequent failure to open.
Various hydraulic control unit valves.
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Core spray system II keep fill pump.
Source and intermediate range nuclear instrumentation.
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Auxiliary cleanup pump.
"D" recirculation pump seal.
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"A" EMRV leaking.
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"D" recirculation pump discharge valve.
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Steam leak on drain line to flash tank.
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Turbine stop valve steam leak.
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"B" cleanup pump head bolt leakage.
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Condenser vacuum breaker not fully closed.
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One of the outage goals was to reduce the inventory of func-tional maintenance work from approximately 600 to 400 work items. The licensee's progress toward meeting this goal was
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reviewed.
At the start of the outage, 577 open maintenance i
items existeo. At the time of reactor startup, 631 open items existed with 824 items completed during the outage.
Inspectors were onsite to provide shift coverage from March 20, 1989 until plant startup on March 26, 1989.
During this period, plant startup was delayed daily due to maintenance activities.
The failure to establish a realistic startup date made it difficult for opera-tions to schedule pre-critical checkoffs and prerequisites. Overall, better coordination between operations and maintenance would have been beneficial to establish a realistic startup date.
The licensee concluded that the only problem which prevented con-tinued plant operability was the
"D" recirculation pump vibration.
The added shutdown time will provide the maintenance group the op-portunity to complete work which was identified during the startup.
Discussions with various personnel indicate a number of tasks which
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were performed during the outage required rework. No effort has yet been made to identify the amount of rework associated with mainten-ance performed during the outage.
2.5 Surveillance 2.5.1 Appendix K (71707)
The licensee had previously identified that under certain conditions (one core spray system inoperable), the plant may not be able to meet Appendix K acceptance criteria.
With only one core spray system available the licensee's Appendix K analysis results indicated that under certain conditions the acceptance criteria may be exceeded.
Lic-ensee corrective action is to restrict core thermal limits to 90% when one core spray system is not operable.
The inspector reviewed the Station Procedures associated with the restriction of the core thermal limits.
These are Sta-tion Procedure 202.1, " Power Operation" and Station Proce-dure 1001.22, " Power Distribution During Power Operation".
The inspector verified that when one core spray system is not operable the licensee has implemented a procedure re-quirement to restrict core thermal limits to 90%.
In ad-dition, the licensee stated that a note had been placed in plant technical specifications, in the core spray section to alert reactor operators that power may be required to be reduced when one core spray system is unoperable.
No un-acceptable conditions were identified.
2.5.2 Plant Loss of Power Surveillance (61726)
On March 12, 1989, the inspector witnessed portions of the plant loss of power surveillance, " Diesel Generator Auto-matic Actuation Test", 636.2.001.
The inspector verified that the procedure was properly approved and that the re-quired approvals were obtained prior to the beginning of the surveillance. The inspector observed the preshift briefing which was conducted with this surveillance.
Dur-ing this briefing all participating parties were presented with an overview of the scope of testing, what equipment response would be, and what verifications were required.
During the testing of the #1 diesel generator, the inspec-tor observed that the peak loading on the diesel was ac-ceptable, and the inspector verified that the required automatic actions occurred.
The inspector noted that minor procedural discrepancies were identified by the licensee and were documented for correction.
The inspector reviewed the procedural discrepancies and concluded there was had no
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impact on the ability of the procedure to verify oper-
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ability of tha equipment.
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During performance of the surveillance'testin,g two problems..
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The first was that some small load molded case n
circuit breakers failed to trip.. The potential safety sig-nificance' of 'this' deficiency.is'that if a sufficient number of these circuit breakers fai.l.to tr.ip, this'would' impose-i additic,nal. loading on-the diesel generator.. In addition',
the tripping of--these molded case circuit. breakers was not -
identified as acceptance. criteria in.the surveillance pro-cedure.
This deficiency was reviewed by a regional based:
inspector and discussed with the licensee. This review was documented in Inspection Report 50-219/89-08. The licensee i
initiated de'viation reports for those molded case circuit'
breakers which did not trip and. initiated work' requests to.
repair.and. replace those circuit breakers which were iden--
tified as needed for plant startup.
The licensee also.
stated that it was their intention to modify the surveil.
lance procedure to incorporate the tripping of.these molded
case circuit breakers into acceptance criteria.for the sur-
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veillance test.
The inspector had.no further questions j
regarding this matter.
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The second problem identified concerned the B Con'trni Rod
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. Drive Hydraulic pump.
During performance of the loss of l
power test, the B Control Rod Drive (CRD) pump motor
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breaker tripped when the pump was sequenced onto the bus.
i Since the breaker received a close signal.to sequence onto i
the bus'as required, the licensee concluded it was a i
breaker problem.
Licensee troubleshooting of the breaker l
and the replacement of the B 'CR0 pump motor is discussed in j
paragraph 2.4 of this report. The inspector had no further
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questions regarding this matter
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'2.5.3 Shutdown Margin Testing'(61707)
I On March 17, 1989, the inspector witnessed the performance of shutdown margin testing by the licensee as performed per
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Station Procedure 1001.26, " Shutdown Margin' Demonstration."
The inspector reviewed the test copy of.the procedure prior to performance of the test and verified that it was pro-perly approved and the appropriate approval signatures had
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been obtained prior to starting the test.
The inspector
also witnessed the preshif t briefing.
During performance j
of the test the licensee corrected some minor problems with
inputs to the Rod Worth minimizer. No unacceptable con-i ditions were identified.
The inspector also reviewed the licensee's shutdown margin certification book.
This is a technique used by the licen-see to verify in a formal manner that all required pre-requisites and plant work have been completed for shutdown I
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The inspector concluded that the shutdown margin certification was an organized, effective method to establish the plant conditions necessary for shutdown mar-gin testing.
2.5.4 Other Tests Observed (61726)
During routine tasks and observations of activities by the inspectors, all or parts of the performance of the follow-ing surveillance tests were observed:
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Drywell Airlock Leak Rate Test, 665.5.005. Test was completed satisfactorily; however, when added to ILRT, results were unsatisfactory.
Retesting of some valves was performed to obtain overall satisfactory results.
Electromatic Relief Valve Operability Test, 602.4.003.
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The "A" relief showed indications of leakage and was scheduled to be replaced following the plant shutdown.
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Turbine Overspeed Test and Calibration, 625.4.001.
Main Steam Valve Position Indication and IST Test,
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624.4.001.
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Torus to Drywell Vacuum Breaker Operability and In-service Test, 604.4.016.
Durino testing performed on March 28, 1989, several valves'Uid not meet test ac-ceptance criteria.
The Technical Specification re-quired actions were taken.
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Source Range Monitor Test and Calibration (Front Panel Test),620.4.004.
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The inspector verified that the tests were performed in accord-ance with approved procedures, that these procedures were being followed, and that the test acceptance criteria were met.
Good communication was maintained between personnel performing the testing and the control room.
In general, personnel perfcrming the testing were carefully following the procedures, and that test results were being thoroughly reviewed.
No unacceptable conditions were identi-fied.
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3.0 Scram Time Testing (61726)
On February 17, 1989, the inspector witnessed the performance of Control Rod Scram Insertion Time Testing, procedure 617.4.003. After completion of this testing, Core Engineering reviewed the strip chart data and iden-tified that several control rods exceeded the Technical Specification acceptance criteria.
Technical Specifications state that the average of the three fastest rods in any two by two array shall not exceed 0.398 seconds at five percent insertion. A total of fourteen two by two arrays exceeded the time of 0.398 seconds.
Although Technical Specifications specify criteria for the control rod five percent travel, there is no notch which corresponds to five percent insertion. The licensee, in the past, has conservatively measured five percent insertion to be notch 45.
Notch 45 corresponds to 6.25 percent i n se rt ' un. The licensee performed an evaluation to apply an adjusting i
multiplier to the measured time (scram signal to notch 45).
The use of this multiplier (0.895) nare accurately estimates the time the control
rods travel five percent. After the application of this multiplier, all
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fourteen two by two arrays met Technical Specification requirements for i
operability. The licensee incorporated the adjusting multiplier into their station procedure.
The inspector reviewed the assumptions and cal-culations of the licensee's evaluation.
The inspector had no questions on the evaluation.
During review of their data, the licensee noted a marked increase in the overall scram times from the previous outage. The licensee concluded that the 11R previous outage data was incorrectly interpreted.
Instead of de-termining the time from the point at which the scram signal is received (corresponding to the lifting of pen number one), the times were deter-mined from the point at which the control rod started to move (corres-ponding to the initial lifting of pen number two). The Technical Speci-fication basis states that the allowable scram insertion time includes a 200 millisecond time delay.
This requi.'s that times must be measured from the receipt of the scram signal. The '4censee has made procedural changes to clarify the requirement that times ut measured from the point when the scram signal is received.
In light of the licensee s conclusion that the interpretation of the pre-vious outage strip charts were erroneous, an in-depth review of the strip charts is needed to determine potential reporting requirements.
Inspector review showed that an in depth review of strip chart data from previous outages was not performed. The apparent cause for the lack of review was Core Engineering's misconception that the strip charts for previous out-ages are not retained.
Core Engineering was not aware that after the strip charts are forwarded to Plant Engineering, Plant Engineering then forwards the strip charts to the Document Control Center for filing.
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The inspector noted that none l
of the 10R outage strip charts had pen number one recorded.
The inspector
concluded that the measured times were potentially underestimated because the time delay for the scram of the control rod was not accounted for.
Pen number one not being recorded indicated that it was inoperable or that
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the chart paper was not running at least one second before the initiation d
of the scram.
In either case, it is contrary to the requirements of the f
station procedure which was in effect at the time.
The inspector dis-cussed his conclusions with licensee representatives.
Core engineering reviewed the data, and utilizing a conservative delay time of 200 milli-
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I second and the adjusting multiplier, and determined that all scram times were acceptable. The insnector reviewed the new procedure and concluded that the changes would preclude the reoccurrence of the 10R testing error.
Core engineering is presently evaluating scram time testing performed during the 11R outage to ensure that similar problems do not exist.
The inspector had no further questions regarding this matter.
4.0 Containment Integrated Leak Rate Testing (70307, 70313, 70323)
On March 7 and 8, 1989, the licensee performed a periodic Containment In-tegrated Leak Rate Test (CILRT) using Station Procedure 666.5.007.
The test was conducted utilizing the Mass point Method endorsed in ANSI /
ANS-56.8-1981. The inspector witnessed portions of this test including in-situ calibration checks of test instrumentation, containment atmos-pheric stabilization, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> CILRT Data Acquisition, and four hour test verification. The inspectors reviewed the CILRT procedure, admini-strative controls and calibration records of the test instrumentation.
Data was recorded and calculated every 15 minutes.
The inspector reviewed and verified the data and computations.
The CILRT passed its acceptance criteria. No unacceptable concerns were identified.
During the depressurization of the drywell, the CILRT procedure directed the performance of the Torus to Drywell Vacuum Breaker test, procedure 665.5.001. The licensee encountered difficulty during this test when attempting to establish a one psi differential pressure between the dry-well and the torus. As the torus was being vented through the torus vent bypass valve, V-28-47, the licensee observed drywell pressure decreasing with torus pressure.
Licensee investigation showed that two torus to drywell vacuum breakers were leaking. The licensee believed that the method for establishing the one psi differential pressure, venting the torus through a two inch valve, V-28-47, did not provide adequate force to seat the vacuum breakers.
The test was reperformed, and the torus was vented through a 12 inch torus vent valve, V-28-17.
The licensee was able to establish a one psi differential pressure and complete the test. The inspector questione" the test methodology.
The rapid depressurization via the larger vent path did not test the acceptability of the vacuum breakers under conditions of a small break loss of coolant accident. A situation may occur in which the rate of pressure increase does not prerate enough force to seat the vacuum breakers and consequently bypass the suppression
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pool heat. sink. The licensee stated that Technical Specifications do not specify how the initial conditions (the test of a one psi differential pressure) are attained. Additionally, the licensee stated that for small breaks of the magnitude in question, bypassing of the suppression pool would be inconsequential.
Subsequently, the licensee repeated the test by slowly pressurizing the drywell with the torus vented. The test was re-peated because of a licensee concern that some of the vacuum breakers were manipulated before the previous test. The results from this third test were satisfactory.
The inspector had no further questions.
-5.0 Containment Spray preliminary Safety Concerns (71707)
As a result of NRC reviews of the licensee's Preliminary Safety Concern (PSC) process, inspectors questioned disposition of several containment spray system PSCs. The licensee agreed to perform detailed reviews of the PSCs before plant restart from 12R Outage. After turning over the de-tailed review of these PSCs to the licensee, inspectors once again read the Preliminary Safety Concerns and were not sure that all potential con-cerns were clearly stated.
The inspector had detailed discussions with the licensee about one concern associated with the containment spray sys-tem. It was concluded that under certain conditions, the control room operators would not be able to establish torus pool cooling as required by the plant Emergency Operating Procedures (EOP).
The licensee initiated a plant engineering work request to review this concern, and this work request resulted in the initiation of a new PSC,
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Licensee review of the PSC concluded that if a design basis ac-cident occurs, the operators could not establish torus pool cooling be-cause the Lo-Lo reactor water signal never clears.
Plant procedures specify the use of the containment spray test return line for. torus pool cooling. This establishes a flow path from the torus through the con-tainment spray heat exchanger and back to the torus.
Containment spray syt:em logic is designed such that on one Lo-Lo level signal, the system will automatically realign from test return to spray the drywell.
On March 16, 1989, the licensee briefed the resident inspector on the de-tails of this concern. The conclusion was that the containment spray logic precluded establishing long-term containment cooling in the design basis accident. Torus temperature could rise to the point where net positive section head (NPSH) is lost to the core spray pumps and the con-tainment spray pumps.
Loss of NPSH to core spray pumps would result in j
loss of cooling to the reactor core and could cause core damage.
I The licensee committed to implement corrective action to address this l
problem before plant restart from 12R Outage.
The corrective action con-sisted of the fabrication of the necessary jumpers and the implementation of the procedure changes directing the operators to install jumpers to defeat the reactor Lo-Lo level signal.
The licensee also lowered the low pressure trip set point of the containment spray pump. The lowering of
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the setpoint allows the operator more time to install the jumpers to de-feat the interlock which prevents establishing torus pool cooling.
The licensee's corrective actions were reviewed by regional based inspectors and documented in Inspection Report 50-219/89-09.
Inspectors concluded that these actions were sufficient to allow control room operators to establish long-term cooling in the design basis accident.
6.0 Licensee Review of Previously Closed preliminary Safety Concerns (71707)
As a result of the number and the potnetial safety significance of unre-solved issues identified in Preliminary Safety Concerns, NRC regional
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management asked the licensee to conduct a review of the previously closed PSC's to verify that no outstanding safety issues remained unresolved.
The licensee conducted this review over a two-day period, March 18 and March 19.
Of 104 PSCs total, 35 were identified for detailed review. On each of these PSCs, a written review was required to state how the concern was resolved. Once these written reviews were generated the licensee convened upper level management and reviewed the dispositions. On the basis of this re-review, the licensee eliminated 26 PSCs. Of the 9 re-maining PSCs, the licensee conducted more detailed reviews and evaluation.
Of the 9 PSCs, five were evaluated as requiring followup action to com-pletely resolve the original concern.
Licensee personnel briefed the resident inspector of the results of this review on March 20, 1989. By letter dated March 21, 1989, the licensee provided the NRC the results of their review of previously closed PSCs.
The inspector reviewed with the licensee the five preliminary safety con-cerns which were evaluated as requiring followup action.
The inspector concluded from this review that these issues did not constitute immediate safety concerns and that licensee proposed corrective action should be sufficient to address the outstanding concerns.
Based on discussions with the licensee, the inspector concluded that the i
licensee response to NRC request to review closed PSCs was prompt, thorough and effective. The licensee review provided confidence that the PSC process had not left significant safety questions unresolved.
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7.0 Appendix R Concerns (71707)
During this inspection period, the licensee identified two Appendix R con-cerns associated with the isolation condenser system.
The first concern was associated with a common fuse which supplies both Appendix R circuits and non-Appendix R circuits. Given the correct combination of grounds, this fuse could blow, resulting in a loss of control power to the isola-tion condenser condensate return valve V-14-35.
In this situation, the valve could not be opened. The isolation condenser is identified as a heat removal mechanism in the licensee's hot shutdown path. A second con-cern involved the isolation condenser high flow isolation signals to the
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Since these AC valves are nor-mally open during plant operation, previous Appendix R reviews had con-cluded that these valves' power circuits were not required to meet re-quirements of Appendix R.
During the review of the first concern, the licensee identified that a scenario existed where grounding of these AC valves' automatic closure signal, followed by a loss of power to the AC valves would result in a loss of the ability to open.these valves, and thus a loss of this heat removal mechanism which is identified in the licensee hot shutdown path.
To address the first concern, the licensee performed a modification to in-stall additional fuses in the control circuit for the isolation condenser valves. This concern is considered resolved.
To address the second concern the licensee is evaluating conduit rewrap-ping and fire wrapping cables in the affected fire zones. The fire zones which are affected are the reactor building 51' elevation, reactor build-ing 23' elevation, the 480 volt switch gear room and the A/B battery room.
As compensatory action the licensee will establish hourly fire watches in these areas to allow plant operation until the concerns can be permanently resolved.
In addition, the licensee is planning to conduct an extensive evaluation for all applicable fire zones to assure a capability to miti-gate undesirable spurious isolation signals in the isolation condenser system. The inspector had no other questions in this area.
8.0 Core Spray Systems Relief Valves (71707)
During the recent refueling outage the licensee replaced both core spray subsystems' booster pump discharge relief valves.
The function of these relief valves is to protect the low pressure core spray system piping from overpressure that may result from the reactor vessel.
Licensee surveillance testing after replacement of the core spray relief valves showed that both valves were lifting prematurely.
The licensee removed both valves from the system and returned them to the laboratory for testing.
Laboratory testing on both valves indicated that the relief setpoints were low.
On one valve the setpoint was 14% low. On the other valve the setpoint was 6% low. The safety significance of these setpoints being low is that if an accident occurs, cooling water flow to the reactor could be diverted to the reactor building equipment drain tank. The lic-ensee installed two different recently tested relief valves in the core i
spray system.
Later core spray system surveillance tests showed that these valves were not lifting prematurely.
The licensee contacted the valve manufacturer and explained to them the deficiencies that had b(en observed on these new relief valves. The manu-l facturer's explanation was that residual stresses from the spring manufac-l turing process had to be relieved. The manufacturer postulated that these l
residual stresses had not been relieved for these two valves and that I
after valve assembly and setpoint adjustment and verification, these
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turer stated that the licensee should indicate as a requirement on pur-chase orders that relief valves be stress relieved.
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The licensee reviewei he deficient conditions for the two valves which had been installed in the core spray system piping to determine the ap-placability of a 10 CFR Part 21 report. The licensee concluded that those conditions were reportable under 10 CFR Part 21 and made the required re-port.
The licensee also reviewed application of valves by this manufac-turer in the plant and concluded that no other valves of this type r/e installed in safety related applications.
The licensee has aprced that before installing these two valves in safety related systame, the set-points will be verified. The inspector had no other T estions in this area.
9.0 Training Review 9.1 Plant Modification Training (417r1)
The inspectors reviewed the Modification Training Instruction (June 26,1988) to determine how plant modifications are incorporated into the operator training program.
The Modification Coordinator, Super-visor Licensed /Non-Licensed Training, and the Program Development Coordinator will determine if a modification warrants specific train-ing. Once it is determined to require training it is entered into the modification database for tracking purposes, and the Modification Coordinator will work with the Lead Instructor to schedule the train-ing. The Modification Training Instruction gives a step-by-step method for ensuring all training material which is affected by the modification is considered for revision.
During the review of this procedure and by later interviews, it was determined that the Modification Coordinator was not on the distri-bution list for all modification materials, as required by the in-struction. This point was discussed at the exit meeting, and the licensee is taking steps to rectify this problem.
Modification training for the 12R outage was initially presented dur-ing the licensed requal cycle 88-7, conducted in September 1989.
Later training was conducted as a part of the Restart Required Train-ing given in February 1989.
This Restart Training was originally scheduled as three 12-hour sessions, requiring individuals to attend at least one session. After the first session was completed, the schedule was revised with the remaining two sessions reduced to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> each. The balance of the training was taught during the Error-Free Startup Training conducted by Plant operations on March 2 and 6, 1989. Because of the length of a single 10-12 hour training session, the effectiveness is questionable.
However, the operator interviews
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show that the majority of operators were satisfied with the modifi-l cation training they received and that they were sufficiently knowl-edgeable of major modifications.
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9.2 Licensed Operator Training Progr_am (41701)
Licensed Operator Training Procedure i~
Oyster Creek Licensed Operator Requalification Training Program Pro-cedure (January 31, 1989) was reviewed to ensure it met the require-ments of 10.CFR 55.59 (c). The operator requalification program is conducted on a cyclic basis so that all program requirements are completed on a biennial basis.
In general seven cycles of training are scheduled each annual period.
The program consists of a planned class room series (lectures), skills training (control manipulation)
and an operational review program (LERs and modifications).. All lic-ensed operators are required to attend scheduled classroom and simu-lator training.. Absences can be made up by attending later weekly presentations during the cycle. Cyclic quizzes are also mandatory
.with a performance standard of 80*4.
A compreher.sive written examina-tion is given,-as a minimum, after each biennial training period.
Operating examinations are given on an annual basis.
The requali-fication procedure also incorporates provisions for an Accelerated Requal Program for those' individuals requiring assignment to a special retraining effort.
The inspectors reviewed the licensee's program for controlling active and inactive licenses. At Oyster Creek only one individual is in an activ's status.and not assigned to an operating crew. As per 10 CFR 55.53 (e) he does perform the function of an SRO for a minimum of seven 8-hour shifts, and this is tracked by the Requal Program Co-ordinator.
Instructors that are in inactive status are also required by the licensee to stand one shift per month, which exceeds the re-quirements-of 10 CFR 55.53.
Oyster Creek Licensed Event Reports (LERs) were reviewed to determine if any of these events can be attributed to a lack of training.
There was no obvious correlation between the LERS and the training the operators received.
It was determined that the Oyster Creek Licensed Operator Training Program meets the requirements of 10 CFR 55.59.
Licensed Operator Training Documentation (41701)
Operator training files for five senior reacter operators and five reactor operators were reviewed.
The individual files were cross-referenced with the training department's master book. Attendance, control manipulations, makeup classes and quizzes were verified.
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The documentation of training meets the requirements of 10 CFR 55.59 (c)(5).
9.3 Licensed Operator Interviews (41701)
Interviews were conducted with three senior reactor operators, five reactor operators anc' members of the training staff.
It was deter-mined that the requalification training is being conducted in accord-ance with the Oyster Creek licensed operator requalification' training program. The majority of the operators indicated that ths: quality and the overall effectiveness of the requalification program has im-proved in the last two years. This trend was attributed to the re-cent increase in training staff.
The operators indicated that there is a communication path which
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exists between operations and the training department so problems and events occurring on shift can be incorporated into the training pro-gram. An example of this was the training that was conducted on isolation condensers as a result of the problems experienced in August-September 1988. The operators are also given the opportunity to evaluate the instructors and training at the end of each cycle.
All operators interviewed felt that the simulator training is valu-able in the performance of their duties, even though it is not a plant specific simulator.
Simulator training was recently increased to twice a year.
10.0 (0 pen) NRC Bulletin 88-07 and Supplement I (TI 2515/99)
An inspection was conducted to verify the licensee.'s implementation of NRC Bulletin 88-07, Supplement I, actions related to the LaSalle " Power Oscil-lation Event".
The inspectors reviewed the applicable procedures and verified that they provide for prompt corrective action to terminate power oscillations.
The licensee updated startup, power operations and recirculation pump proce-dures. The abnormal operating procedure (ABN) for a recirculation pump trip was also updated. An additional ABN (Power Oscillation ABN-3200.34, was developed which specifies actions required to reduce the potential for fuel damage resulting from undamped power oscillation.
One deficiency was noted in the procedure review in that the LPRM indi-cation was not addressed as evidence of thermal hydraulic instabilities.
Supplement I defines power oscillations as APRM peak to peak oscillations greater than 10% or LPRM upscale or downscale alarms. At Oyster Creek, where LPRM power indication is available to the operator, it should be
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used to classify power oscillations'and be incorporated into their pro-cedures. This observation was discussed with the licensee at the exit meeting, and they stated that their engineering. group would review this issue.
Licensed operator training was conducted immediately after. NRC Bulletin F
88-07 was issued and the information was permanently included into the course outline.
The plant simulator training was also used to reinforce operator response to power oscillation.
Lesson plans were reviewed and were determined to address undamped power oscillations. All operators interviewed were thoroughly familiar with the LaSalle event and suscepti-
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bility of the Oyster Creek plant to this problem.
Training on all pro-cedural changes was included in the Restart' Requal. Training (February 1989) as well as the Error Free.Startup Training (March 1989).
11.0 Air Operated Valves in Standby Gas Treatment System (SGTS) (71707)
During this outage, the licensee tested several air operated valves in the Standby Gas Treatment System (SGTS).
This testing determined that the as found condition of the associated accumulators and air piping was inade-quate to ensure that the SGTS would perform its design function. The licensee addressed this problem by reducing the-air leakage in the accumu-lator and associated piping, and developing a temporary air supply proce-dure to the SGTS valves.
This procedure, A100-EAS-3810.01, was written to ensure that the extended operation of the SGTS is possible upon a loss of instrument air.
The Instrument Air System is a nonsafety related system.
The inspector reviewed this procedure and walked down the system to ensure procedure adequacy and proper staging of equipment.
The procedure refer-enced a " Temporary Supply Air Kit" which is stored in the warehouse and staged for implementing the procedure.
The inspector noted that this kit contained air tubing which was too short to permit the successful execu-tion of this procedure.
This fact was brought to the attention of the licensee and was corrected. The inspector noted no other discrepancies.
12.0 Licensee Action on Previous Inspection Findings (71707)
(Closed) Violation 85-35-08. This item addressed the concern that person-nel leaving the radiological controlled area (RCA) were not frisking out books or other hand carried items.
In particular, personnel who had carry
items in their hands would frisk one half of their body while holding items in their hand not being frisked.
Upon completion of the first half of the body frisk, the individuals would turn 180 degrees, shift the items to the other hand, complete the second half body frisk, and then leave the RCA without frisking the carry-along items.
This is a violation of GPUN Procedure 915.26, which states that all items leaving the RCA must be frisked.
Licensee action to correct the deficiency was to emphasize the need to frisk all hand held items prior to leaving the RCA.
Large signs were also posted at all frisking stations to remind personnel to frisk all
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hand held items prior to leaving the RCA.
Radiological Control Techni-cians were directed to frisk all hand carried items that were leaving the RCA. The inspector verified that signs were posted which reminded per-sonnel to frisk hand carried items prior to leaving the RCA.
The inspec-tor also verified that Radiological Control Technicians were frisking hand carried items.
Based on inspector review of the licensee corrective ac-tion, this item is considered closed.
(Closed) Violation 86-12-05. This item concerned the.' failure to replace welds on three isolation condenser snubbers which subsequently rendered them inoperable. This led to violation of.a Limiting Condition for Opera-tion (LCO). The welds in question were removed by a contractor to allow modification work to.be performed on isolation condenser piping. Once the modification work was completed, these welds were to have been replaced per the job package, but they were not. This fact was not discovered until two years after the. modification work was completed.
Resident in-spectors. discovered the missing welds while conducting a routine walkdown of the isolation condenser piping. The failure to replace the welds on the snubbers rendered the snubbers inoperable which necessitates entering an LCO action statement.
The action statement requires that once the snubbers are declared inoperable, they must either be repaired or. replaced within 72 l'urs.or the plant must be shut down in 7 days.
Since neither action stt'ement was implemented, a violation of Technical Specifications occurred.
Jubsequent investigation into the event revealed that the con-tractor's quality assurance program was not effectively implemented by the contractor's site menagement. To correct the deficiency and preclude the occurrence of a similar event, the following corrective actions were taken.
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The missing welds were replaced and site access to the Oyster Creek and TMI site was denied to the contractor's quality assurance (QA)
supervisor and project manager.
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An interview process for prospective contractors was implemented.
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The contractor's quality assurance program implemented several im-provements that would ensure proper documentation of welds.
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GPUN was to examine its own administrative process for controlling work performed by contractors and upgrade procedures, if necessary, which controlled: the acceptance of work performed by contractors, control of contractor work performed onsite, and the method by which the scope of contractor work is changed on site.
The inspector verified that the corrective actions were taken by GPUN. No further action is planned on this item.
(Closed) Item 86-11-03. This item concerned the failure of the licensee to secure the nitrogen-oxygen cylinders on the reactor building 75'0" elevation. The cylinders in question were chained in place in a manner
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that may not provide adequate support.
To address concern and other ques-tions regarding the storage of components, the licensee developed an equipment storage procedure, GPUN Administrative Procedure 119.05, This instruction provides guidance on the proper storage of items in safety related areas.
In particular, it calls for compressed gas cylinders to be secured by two 3/8" nylon ropes located at distances approximately 1/3 and 2/3 of the height of the cylinder. During tours of the facility, the in-spector verified that compressed gas cylinders were either stored in a metal rack or secured to a suitable structure per the GPUN procedure.
Based on observations and review of the GPUN Administrative Procedure 119.05, no further action is required on this item.
[ Closed) Two Issues That Had Been Raised in Inspection Report 50-219/88-38.
The first concern dealt with the licensee's discovery and resolution of loose wires in control room panels 5F, 6F, and 11R.
The licensee had originally initiated a job order (JO 14884) requesting a detailed inspec-tion of wire connections in control room panels 3F and 8R. This J0 was revised and expanded to include panels ER 18A, 4F, IF, 2F, 11R, 5F, 6F, and 10R.
In addition, the licensee issued a separate job order (JO 15099)
requesting a visual inspection of all control room panels and ER 18A and ER 188. The purpose of this inspection was to identify and boot all un-terminated wires. As a result of discussions with the resident inspector, this JO was expanded to include inspection and documentation of all ter-minated wires showing signs of stress or looseness in order to resolve the question of loose wires before plant restart. All discrepancies dis-covered in J0s 14884 and 15099 were recorded on Material Nonconformance Reports (MNCR).
In order to close these two J0s, a third JO (JO 15107)
was generated requesting repair of all MNCRs from J0 14884 and 15099.
Through discussions with licensee and contractor personnel and through review of work packages, the inspector determined that all pertinent MNCRs had been adequately resolved (JO 15107 was closed by the licensee on 3/15/89).
Related to the discovery of loose wires in control room panels: the lic-ensee critiqued the incident which occurred when a loose wire in panel 11R was relanded, and an unexpected plant response resulted.
Critique Report PE88-001 attributed the cause of the event to personnel error (not fully researching the electrical connection) and to inadequate drawings.
Per-manent corrective actions were to include the critique as required reading for plant maintenance, engineering, and operations personnel; and upgrad-ing electrical drawings to facilitate troubleshooting by improved legi-bility, including functions of wires on the drawings.
The second concern raised in the inspection report was IRM spiking prob-lems.
These IRM spikes caused inadvertent full scram and half scram sig-nals.
The inspector discussed the matter with two members of the licensee plant engineering staff who have been working on the resolution of the w __
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problem. The licensee stated there are two primary causes'of the spiking signals: (1) electronic " noise" in the drywell area where the IRMs are physically located; and (2) physical degradation of the IRM lead cables.
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The licensee is resolving these problems on an as-needed basis. The noise problem is being resolved with the addition of grounding. straps to the lead cables.. Physically degraded cables are being-detected by a~new PM l.
procedure using an accelerometer. - Damaged lead cables, which are a j.
ribbon-type cable, are being replaced by coil-type cables'which are more resilient to wear.. The licensee stated that there have not been any scram signals generated by spiking IRMs since the ones noted in Inspection Re-port 50-219/88-38..The inspector had no further questions.
13.0 Backshift Inspections NRC inspections of licensee activities on backshifts were conducted on the following dates:
March 4 March 5 March 12 March 17 March 18 March 19 March 20 March 24 March 25 March 26 14.0 Exit Interview (30703)
A summary of the results of the inspection activities performed during this report period were made to senior licensee management at-the end of this inspection.
The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.
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