IR 05000219/1992025
| ML20128P620 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 02/10/1993 |
| From: | Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20128P612 | List: |
| References | |
| 50-219-92-25, NUDOCS 9302250024 | |
| Download: ML20128P620 (29) | |
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U. S. NUCLEAR REGULATORY COMMISSION i
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REGION I
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j Report No.
92-25
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j Docket No.
50-219
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j License No.
Licensee:
GPU Nuclear Corporation l
l 1 Upper Pond Road j
Parsippany, New Jersey 07054
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Facility Name:
Oyster Creek Nuclear Generating Station i
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Inspection Period:
December 15,1992 - January 18, 1993 i
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Inspectors:
John Nakoski, Resident Inspector
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j Dave Vito, Senior Resident Inspector i
i Tim Frye, Reactor Engineer l
Sam liansell, BWR Licensing Examiner, DRS
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Approved By:
TIA MM//ff pm Rogge, Sectioidfief Date
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Reactor Projects Section 4B f
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Insnection Summarv: This inspection report documents the safety inspections conducted
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during day shift and backshift hours of station activities including: plant operations;
radiological controls; maintenance and surveillance; engineering and technical support; I
emergency preparedness; security; and safety assessment / quality verification.
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Resulti: - Overall, GPUN operated the facility in a safe manner. A violation of 10 CFR
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50.71(e) was identified because design information related to a 1984 modification of the torus
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suction strainers had not been included in the FSAR. An unresolved item was'noted-i regarding a December 11,1992, reactor scram signal received during movement of the
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i reactor mode switch from the shutdown position to the refuel position. The licensee did not i
want to troubleshoot the mode switch while it was locked in the refuel position and had yet j
- to assess whether the cause of the scram signal was operator performance related, an i
equipment problem, or a combination of both,
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TABLE OF CONTENTS hgu EXECUTIVE SuhthiARY
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1.0 O pERATIONS (71707).................................... I 1.1 Operations Sum mary.................................
I 1.2 Reactor hianual Control System Operability................... 2 1.3 Control of Control Room Documentation..................... 4 1.4 hiode Switch Scram (URI 50-219/92 25 02)
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1.5 Site Specific Simulator................................ 6 1.6 Facility Tours
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2.0 RADIOLOGICAL CONTROLS (71707).......................... 7 3.0 h1AINTENANCE/ SURVEILLANCE (62703,61726)..................
3.1 hiain Steam Line Plug Removal
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3.2 Emergency Diesel Generator hiaintenance....................
3.3 Service Water / Emergency Service Water Piping Inspection / Replacement...............................
3.4 Station Blackout Functional Testing........................ I1 3.5 Reactor Water Cleanup Valve Electrical Testing
......,,.......13 4.0 ENGINEERING AND TECHNICAL SUPPORT (71707,40500)........... 13 4.1 Recirculation Loop Safe End Boat Sample...................
4.2 Core Spray Sparger Evaluation..........................
5.0 SECURITY (71707)
....................................15 6.0 SAFETY ASSESSh1ENT/ QUALITY VERIFICATION (40500)..........
6.1 Engineered Safety Feature Suction Strainer Assessment (VIO 50-219/92-25-01)
....................................15 6.2 Process Re-engineering Program Update....................
6.3 Quality Assurance hionitoring of Equipment Operator Rounds.......
7.0 REVIEW OF PREVIOUSLY OPENED ITEhtS (92701,92702)...........
8.0 EXIT h1EETINGS AND UNRESOLVED ITEhtS (40500,71707).........24 8.1 Preliminary inspection Findings
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8.2 Attendance at hianagement hiectings Conducted by Other NRC I n s pec to rs.......................................
2 4 ATTACHh1ENT 1: Figure 1, A GEh1AC Sensing Line Figure 2, B GEh1AC Sensing Line i
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EXECUTIVE SUMMARY Oyster Creek Nuclear Generating Station Report No. 92-25 Plant Operations Overall, the plant was operated in a safe manner. Operators were cognizant of current outage activities and complied with the prescribed risk management guidelines for plant outage configurations. On December 11,1992, a reactor scram signal occurred while placing the reactor mode switch in the refuel position. The licensee completed initial certification of the Oyster Creek plant-specific simulator on December 31,1992.
Radiological Controls Radiological controls established during the outage have been effective in reducing the exposure received by workers and the incidence of radiological events. On December 23, 1992, a worker was contaminated while cleaning tubes of a moisture separator reheater with pressurized air. The resulting body burden was low. This matter is discussed in NRC Inspection Report 50-219/93-01.
Maintenance /Surveillarn The modincation, maintenance, and return to service of emergency diesel generator No I was donc properly and effectively. Functional testing of the station blackout modification was well controlled and demonstrated the ability of the offsite Jersey Central Power and Light (JCP&L) combustion turbines to provide a reliable alternate ac power to the station.
Other outage maintenance / surveillance activities have been generally well controlled and
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coordinated.
Engineering and Technical Support Engineering support for major outage activities was good, particularly for the station blackout modification and the emergency diesel generator overhauls. The licensee a,npropriately responded to an issue related to an apparent defect found during ultrasonic testing of the "D" recirculation loop discharge safe end.
Safety Assessment and Ouality Verincation An operations quality assurance (OQA) effort to ascess the performance of equipment operator tours was aggressive and performance-based. The OQA findings were adequately addressed by the operations department. Inspector assessment of torus suction strainer design information found that information related to a 1984 modification of the strainers had not been included in the Oyster Creek Final Safety Analysis Report (FSAR).
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DETAll3 1.0 OPERATIONS (71707)
1.1 Operations Sununary
The licensee started the 14R refueling outage on November 28,1992. During this inspection
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period, the licensee performed the bulk of the planned outage work activities. In addition to the planned activities, the licensee had identined significant work that was added to the original scope of the refueling outage. During this inspection period, the inspectors observed outage activities including ongoing work, daily planning and scope control meetings, and the licensee's handling of emergent work and deficient conditions.
l On December 16, 1992, the licensee completed core offload. Signincant work completed
during this inspection period included exchange of the electro matic relief valves (EMRV)
and safety valves (SV). Seventeen control rod drive mechanisms (CRDM) were replaced.
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The A and B station batteries manufactured by Gould were replaced with batteries manufactured by AT&T. Additional NRC review of the modification supporting the battery
exchange was in progress at the end of this inspection period. Both emergency diesel generators (EDG) were overhauled. To address issue. related to station blackout (SBO)
response capabilities, the licensee completed IX: r 'cdification that provided an alternate ac power source from the combustion turbines bc.d w the site. To improve reliability and
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performance of the recirculation pump motor scayr (MG) sets, all five MG sets were
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overhauled. Work continued on the drywell steel ilner corrosion mitigation project. The licensee has removed tl e corrosion material from the lir.2r, hydrolared the liner surface, and
started applying an epoxy coating to the liner.
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Some additional work scope was added to the outage due to identified deficiencies. This
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included fillet weld cracks in two steam dryer supports that required repair. All of the
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recirculation pump MG set feeder cables were replaced based on failure of high potential (hi-pot) testing. As a result of the as-found local leak rate test (LLRT) on the B outboard main steam isolation valve (MSIV) (NSO4B), the licensee rebuilt the valve. Similarly, the licensee
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replaced the spring and rebuilt the actuator for the B inboard MSIV (NS03D) when the LLRT results were unacceptable. The licensee also repaired a leaking pump cover to easing joint on the E recirculation pump by seal welding the joint. The leak had been identified early in the outage and had to be repaired before performance of the ASME leak test of the reactor coolant system.
Core reload was started on January 2,1993. During reload two of the fuel support casings were unseated 6. iring control rob blade movement. This was identified when the fuel assemblies were placed into the cell. The improper seating was determined to be the result of control rod blade movement performed to support CRDM exchange and reactor vessel (RV) internal visual inspections. The licensee was able to re-seat the fuel support casings
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without the need to remove the fuel assemblics from the cell. Inspectors observed both defueling and refueling of the core during the outage. Based on these observation the inspectors concluded that the reactor operators (RO) and senior reactor operators (SRO)
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2 performing the fuel movements controlled core alteration well. Difficultles that were encountered, like the problems with the fuel support casing, were resolved quickly.
Coordination between the licensee and their contractor for refueling activities (General Electric) was good. Reload was completed on January 7,1993.
Throughout the outage, the licensee has maintained good outage risk management perspective. Seven distinct plant configurations were established during which specific equipment was required to remain available to support planned outage activities and respond to unplanned events. The transition between each risk management plant configuration was well controlled. Systems required to be restored to service before transition to another plant configuration were returned to a functional condition in a timely manner to support the transition, in each plant configuration, multiple RV water inventory makeup paths were available, along with the electrical power to support each path. Control room personnel were provided with the systems and/or components required to be available on a daily basis to support the risk management approach. This information was not limited to the minimum requirements, but included the equipment expected to be available for a given period in the outage above the minimum requirements.
At the end of this inspection period the licensee was continuing their aggressive outage schedule to support plant startup. The licensec was effective in incorporating emergent work into the scope of the outage. The most notable emergent work issue was the need to repair NS03D. This work was not completed before the reactor vessel internals were replaced. As a result the licensee was required to plan an alternate window of opportunity to perform the as left LLRT for NS03D.
The inspectors concluded that the licensee was implementing an effective outage risk management program. An additional benefit from the risk management program was control of work activities. The various organizations performing wcrk at the site were required to complete discrete packages of work to support transition from one plant configuration to another. This supported and complemented the system out of service process the licensee used to control work. Control of emergent work was performed well and effectively integrated into the existing schedule. Fuel movement operations were well controlled and conducted. Ongoing work observed by the inspectors during the inspection period was performed well. Overall, the inspectors concluded that the licensee's performance during the 14R refueling outage was significantly improved over previous outages.
1.2 Reactor Manual Control System Operability The inspectors reviewed the licensee's formal interpretation of required actions in response to the failure of the control power fuse (4F2) for the reactor manual control systern (RMCS).
Corrective actions in response to past occurrences of this fuse failure had been inconsistent.
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Prior to a September 16,1992,4F2 fuse failure, the licensee practice was to declare all 137
control rods inoperable and commence a reactor shutdown as required by Technical l
Specification (TS) 3.0.A. In response to the September 16,1992, occurrence, the group I
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shift supervisor deciated all the control rods inoperable, but no actions were taken to start a l
reactor shutdown. The fuse was replaced and the RMCS and control rods were declared operable within an hour of the fuse failure. See section 1.2 of NRC inspection report 50-219/9219 for additional details, in response to inspector questions following the September 16,1992, event, the licensee re-evaluated their position regarding expected actions to be taken when the RMCS becomes inoperable due to the loss of RMCS control power. A Plant Review Group (PRG) meeting
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was held on October 19, 1992, to review the issue. The PRO concluded that the control j
rods were not required to be declared inoperable in the event that control power was lost to i
the RMCS. This conclusion was based primarily on the fact that even though the capability to manually move the control rods is lost when the control power fuse fails, contrcl rod scram capability remains. Ilowever, the PRG noted that when control power is lost to the
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l RMCS, the hydraulic control unit (liCU) trouble alarm in the control room is also lost. To ensure that the operability of the HCUs can be assessed, the PRG recommended that liCU accumulator gas pressme be monitored continuously when RMCS control power is lost.
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i The Oyster Creek UFSAR describes the function of the RMCS as an important system that controls processes (normal control rod motion) having a significant impact on plant safety, but is not required to perform a safety function following anticipated operational occurrences or accidents. The Oyster Creek TS does not address the operability of the RMCS. The UFSAR describes the reactivity control system as consisting of movable control rods,
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burnable poison, and a reactor recirculation flow control system. ANSliANS-52.1, dated 1983, defines a reactivity control system nuclear safety function as being able to achieve and maintain the reactor suberitical for any mode of normal operation or event or to introduce negative reactivity or limit the introduction of positive reactivity for specified events. The non-nuclear safety function of a reactivity control system is to resist failures that could prevent any safety-related equipment from providing its nuclear safety function and provide reactivity control for normal operation. Typical nuclear safety-related reactivity systems
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consist of components necessary for reactor trip (such as control rods, control rod drives, and those portions of the CRD HCUs used for rapid insertion of control rods, liquid poison
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control systems, recirculation pump trip systems, and reactor coolant recirculation flow control).
Following review of the UFSAR, Oyster Creek TS, and ANSI /ANS-52.1-1983, the licensee
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concluded the RMCS was not intended to be part of the safety-related aspects of reactivity
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control systems, insertion of the control rods during anticipated operational occurrences or
accidents is provided by the CRD system and HCUs associated with each control rod,
Operations department management has reviewed the PRG position on RMCS and control rod operability. In response, operations management provided instructions to control room personnel on this issue. When the control power fuse for the RMCS fails, the control rods are not required to be declared inoperable. However, a continuous local watch of HCU accumulator gas pressure is required to provide assessment of continued control rod
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operability. The licensee has stated that prompt action will be taken to resolve failures of the control power fuses to the RMCS. If cause of the fuse failure cannot be determined in a short time, the licensec has stated that more conservative actions will be considered,
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including reactor shutdown.
The inspectors reviewed the licensce's position on RMCS operability effects on control rod operability, reviewed the UFSAR, Oyster Creek TS, and ANSI /ANS-52.1-1983, and discussed the issue with operations and licensing department personnel. The inspectors concluded that the licensee had performed a reasonable evaluation of the effects of the loss of control power to the RMCS on control rod drive operability. Further, the inspectors j
concluded that the licensee had developed appropriate actions in response to a loss of RMCS i
control power.
1.3 Control of Control Room Documentation i
During a review of control room documentation, inspectors noted that several documents were not controlled. These documents consisted of piping and instrument drawings (P&lD),
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an electrical load list, as built drawings, and Operations Plant Manuals. The inspectors questioned the licensee on the practice of having uncontrolled documents in the control room.
13ased on the inspectors' questions, the licensee started a review of the documentation in the control room to determine what uncontrolled documents were currently in the control room
and how access to and use of this documentation should be controlled. Following the review, the licensee removed all uncontrolled documents except the three P&lD folders and
the encontrolled electrical load list. To provide direction that the P&lDs and electrical load list were for reference only, operations management has applied a distinctive label to each binder indicating that the information shall be used for reference only.
The inspectors later toured the control room and verified that the only uncontrolled documents in the control room were the three P&lD binders and the electrical load list. The
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Manager, Operations Support indicated to the inspectors that the electrical load list had been verified to be accurate, but that the load list will not be updated as a controlled document.
Operators have been instructed to use the computer-based daut management system (GMS2)
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and controlled electrical prints to determine electrical loads for system isolation and tagouts.
The inspector reviewed the labels to be applied to each of the P&lD binders and electrical load list.
The inspectors concluded that the licensec had adequately reviewed the control of documents in the control room. While it is not preferable to have uncontrolled documents in the control room, the licensec's efforts to restrict the use of the P&lD books and the electrical load list as reference documents only should preclude the of these documents to operate the plant.
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1.4 Mode Switch Sernm (URI 50-219/92-25-02)
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On December 11,1992, while placing the reactor mode switch in the refuel position from the
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shutdown position a reactor scram signal occurred. The lleensee was preparing to commence
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reactor defueling during the 14R refueling outage. Procedure 205.4, revision 19, " Core Offloading (Defueling)/ Refueling," directed the control room operator (CRO) to place the mode switch in the refuel position from the shutdown position. The CRO had difficulty j
moving the mode switch into the refuel position and removing the key from the keylock l
switch. The scram signal was caused because the CRO took longer than two seconds to
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move the mode switch and remove the key. The two second time delay is provided within the mode switch circuitry to allow the mode switch to be moved from the shutdown position to the refuel position without causing a scram signal. The keylock switch provides the means to lock the mode switch in the appropriate position,
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The inspector reviewed procedure 205.4, revision 19, reviewed the Operations Plant Manual
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Chapter on the reactor protection system (RPS), discussed the issue with several operations department personnel, and discussed the issue with the group shift supervisor (GSS) in the
control room at the time of the event and the CRO that operated the mode switch. Procedure 205.4 did not reference the time delay associated with placing the mode switch in the refueling mode from the shutdown mode. Ho.vever, the operations department personnel
interviewed were aware of the time delay and its purpose. In addition, the Operations Plant Manual Chapter on the reactor protection system, uad during licensed operator training,
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provides a detailed description of the timers associated with the shutdown position of the
mode switch. Both the involved GSS and CRO stated that difficulty was encountered when removing the key from the keylock switch after the CRO had placed the mode switch in the refuel position. By the time the operator had removed the key from the keylock switch, the
two-second time delay had expired. Because the mode switch had not been removed from the shutdown position completely, the mode switch circuitry input a scram signal to the reactor protection system (RPS).
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Based on the discussion with the GSS and CRO, it was difficult to position the mode switch
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in the refuel position and remove the key within the time provided by the time delay. When discussing the event with the involved CRO, the inspector was informed that while the CRO j
was experienced in other mode switch operations, this was the first time the CRO had moved the mode switch from the shutdown position to the refuel position. The licensee is still evaluating what corrective actions will be taken, if any, to preclude recurrence of this event.
The licensee did not want to troubleshoot the mode switch while it was locked in the refuel
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position and had yet to assess whether the cause of the scram signal was operator performance related, an equipment problem, or a combination of both. This item will remain unresolved pending completion of the licensee's evaluation and corrective actions (URI 50-219/92-25-02).
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1.5 Site Specific Simulator l
The Oyster Creek plant specific simulator was delivered to the site on November 30,1992.
Factory acceptance te; ting had been puformed at the Westinghouse Electric Corporation facility in Monroeville, PA, prior to shipment to the site. GPUN undertook an aggressive onsite certincation test effort to complete certification of the simulator by December 31, 1992, in accordance with 10 CFR 55.45(b)(5), GPUN submitted a letter to the NRC on December 31,1992, documenting certification of the Oyster Creek simulator as a valid
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training tool. This letter also noted that a supplemental report to the initial certification would be submitted by February 28,1993, and would include a description of those characteristics that could not be tested or verined by the Westinghouse factory acceptance
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testing.
The onsite certi6 cation effon was k progress during an inspector tour of the new simulator on December 17, 1992. The replication of the actual Oyster Creek control room con 0guration was well done, although some auxiliary systems such as hydrogen injection have not been included in the simulator. The onsite testing has progressed well with only
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some minor deficiencies.
During plant startup after the 14R outage, GPUN will be taking data related to response time for feedwater demand to support the future installation of digital feedwater and recirculation Dow control in both the plant and the simulator. The designer for the digit: Dw control
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systems had assumed an immediate response to feedwater flow demand. Hcuever, Oyster Creek operations and engineering personnel noted that historically there has been a several second time delay between feedwater demand and level response. The new digital flow control systems are scheduled to be installed in the simulator after the upcoming requalification exams are given in August 1993. The time frame between installation of the new flow control systems and the 15R refueling outage should allow adequate time for the operators to gain familiarity with the system.
On January 4,1993, GPUN requested a one-time schedular exemption from the requirements of 10 CFR 55.59(a)(1) and (c)(1) to extend the operator requalification period from 24 to 32 months so that both the written and operating portions of the upcoming requalincation exams can be administered in August 1993. This exemption request is currently under NRR review.
1.6 Facility Tours The inspectors observed plant activities and conducted routine plant tours to assess equipment conditions, personnel safety hazards, procedural adherence, and compliance with regulatory requirements. Tours were conducted of the following areas:
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e control room o
intake area cable spreadir.g room
reactor building e
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turbine building i
e diesel generator building e
e new radwaste building
vital switch ear rooms E
e old radwaste building e
access control points e
transformer yard
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Control room activities were found to be well controlled and conducted in a professional manner. Inspectors verined o;wrator knowledge of ongoing plant activities, equipment status, and existing Dre watches through random discussions.
2.0 RADIOLOGICAL CONTROLS (71707)
During entry to and exit from the radiologically controlled area (RCA), the inspectors verined that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive
contamination, and monitoring instruments were functional and in calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify
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that they were current and accurate. The inspectors observed activities in the RCA and
verified that personnel were complying with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the area.
Radiological controls established during the outage have been effective in reducing ihe
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exposure received by workers and the incidence of radiological events. Improvements in job planning and performance, and radiological engineering support in job package A'LARA reviews have resulted in the licensee establishing an outage exposure goal of 700 person-REM. By the end of the inspection period, the licensee was continuing to maintain outage exposures within their outage exposure goal. The number of radiological concerns identified since the start of the outage has been limited.
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On December 23,1992, a worker was contaminated while cleaning tubes of a moisture separator reheater with pressurized air. The resulting body burden was low. This matter is discussed in NRC Inspection Report 50-219/93-01.
3.0 MAINTENANCE / SURVEILLANCE (62703,61726)
3.1 Main Steam Line Plug Removal On January 10, 1993, the inspector observed removal of the main steam line (MSL) plugs installed to support refueling outage activities. The licensee had purchased new MSL plugs for the 14R refueling outage that provided for use of the plugs as a test boundary for the local leak rate testing of the inboard main steam isolation valves with the refuel cavity Gooded in support of the last refueling outage (13R), the licensee had purchased a MSL plug installation / removal tool from ABB Atom that allowed the plugs to be installed and removed while the refueling cavity was Gooded.
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Difficulties were encountered during the initial attempt to use the hfSL plug installation /
removal tool for removal of the new MSL plugs. The gripper on the tool was not fully engaging on the spud on the MSL plugs. This prevented the tool from pulling the MSL plugs out of the main steam line vessel penetrations. The licensee used an underwater camera to assist in ensuring that the gripper fully engaged the spud on the MSL plug and was eventually successful in removing the plugs with the tool.
Based on this experience the licensee is evaluating methods to improve the ability to align the MSL plug installation / removal tool and to verify that the gripper is fully engaged on the spud of the MSL plugs. Additionally, the licensee is evaluating the possibility of simultaneous operation of the two sets of plug installation and removal assemblies on the MSL plug installation / removal tool.
The inspector observed the successful attempt to remove the MSL plugs on January 10, 1993. The crew operating the MSL plug installation / removal tool were familiar with the operation of the tool. Coordination of the camera. lights, and equipment was adequately performed. Difficulties encountered during the successful removal attempt were resolved in an appropriate manner As a contingency the licensee was developing a plan to remove one of the MSL plugs at a time using higher air pressure to the gripper actuator.
The inspector concluded that the licensee had adequately controlled the MSL plug removal.
Difficulties encountered were appropriately resolved and the licensee was evaluating long-term corrective actions to prevent recurrence during the next refueling outage.
3.2 Emergency Diesel Generator Maintenance The inspectors observed the outage overhaul, modification, and return to service of emergency diesel generator (EDG) No.1. The inspectors also reviewed the documentation related to the work performed, the modifications installed, and the post maintenance testing and return to service, Overall, the work was done well and the functionality of the diesel and the installed modifications was appropriately verified.
Modifications of the diesel generator included the following:
relocation of relays and contacts within the engine compartment to the generator o
compartment to reduce equipment head exposure; installation of permanent test leads and keylock switches to minimize requirements for e
jumpers and lifted leads during start and protective relay testing; replacement of the under-frequency relay; e
installation of small exhaust fans in the stcrting battery compartments to preclude e
hydrogen buildup; and
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9 modification of the starter motor actuation circuitry to facilitate engagement of the e
starter motor pinions to the engine flywhccl.
In addition to these modifications, several components were replaced in accordance with the replacement schedule provided in Appendix I of surveillance procedure 636.1.010, " Diesel Generatur Inspection (24 month)," Revision 6, dated December 13, 1992. Specifically, system filters, water pumps, engine driven pumps, water system seals, the lube oil bypass valve, and the cooling fan belts were replaced.
The inspectors observed portions of the modification work and of the performance of several surveillance procedures which controlled the inspection overhaul, and verification of post-maintenance operability of the diesels. The inspectors observed the relocation of wiring and
the installation of the permanent test jumpers. The technicians performed the efforts carefully, referring consistently to the up-to-date drawings and wiring lists provided with the
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jobpackage. The field wiring was appropriately verified after work completion. Most of the field change requests to the work packages for the diesel outage work were due to the
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wiring modifications. The lead engineer for this effort noted that the need for field changes was expected due to the large number of wiring changes to be performed.
The inspectors observed the adjustment of the cylinder exhaust valves and injectors. The adjustments were performed by two technicians from Power Systems, a service contractor that frequently performs maintenance work on the Oyster Creek diesels. One technician manually cranked the engine to put the exhaust valves in the proper position for adjustment
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while the other technician performed the adjustments. The technician performing the adjustments did not refer to the diesel vendor manual during the adjustment but appeared to be very knowledgeable with regard to the necessary tolerances. The inspector reviewed the diesel vendor manual which had been available at the job site for reference and verified that the technician's actions had been appropriate.
The inspectors also observed portions of the performance of surveillance procedure
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636.2.009, "EDG Protective Relay Surveillance," Revision 5, dated February 13,1989, and the post-maintenance performance of surveillance procedure 636.4.003, " Diesel Generator Load Test," Revision 44, dated October 26,1992. The inspector verified that the procedure prerequisites had been appropriately completed. The protective relay checks, operational trip testing, and load test were completed successfully and in accordance with the procedures.
The inspectors concluded that the modification, maintenance, and return to service of EDG No. I was done properly and effectively. During the EDG No. I work, the system outage coordinator (lead engineer) continuously monitored work progress and field changes and used this information effectively to facilitate work on EDG No. 2 which began after returning EDG No. I to service. Good communication among the technicians, work supervisors, startup and test personnel, plant engineering, and operations personnel was noted throughout the effort.
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The work performed during the 14R outage essentially completed the mechanical engine work portion of the licensee's program for modification of the Oyster Creek EDGs. The starter motor pinion engagement modification was the only modification performed as a result of a regulatory issue (see NRC inspection reports 50-219/91-01 and 50-219/91-25 for
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more detail). The modifications were derived from a voluntary licensee program to improve the performance and reliability of the diesels. The remainder of the program involves the
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completion of planned electrical work during the 15R refueling outage, including the addition
of performance monitoring equipment and upgrade of the governor control system.
Structural work on the diesel building roof and concrete flooring is scheduled to be
performed during the 16R refueling outage.
3.3 Service Water / Emergency Service Water Piping Inspection / Replacement
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The licensee completed repairs of the leak in the 20-inch service water supply pipe below the i
condensate transfer pump house (additional detail on this issue is provided in NRC Inspection Reports 50-219/92 21 and 50-219/92-23). The leak had been physically located on November 14, 1992, in a horizontal section of the carbon steel service water supply line
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i about 20 feet below the ground surface, close to a flanged elbow that directed the flow vertically. The pipe defect was observed to be a 4-5 inch longitudinal opening near the flanged elbow. Immediate action was taken at the time to contain the leak, which had
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increased to 30-50 gpm after the exterior pipe coating broke loose, with a banded clamp.
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During the outage window for service water system work, the portion of the service water system which contained the crack was cut out and replaced with a spoolpiece. The opening
was determined to have been caused by external pipe wall corrosion after degradation of the external coal tar epoxy pipe coating. The defect was not due to crosion/ corrosion.
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GPUN also performed visual and ultrasonic inspection of the interior and exterior surfaces of accessible service water piping in the excavation area. These inspections revealed no other areas of wall thinning. Some minor pitting was noted on the inner pipe surface in an area of the horizontal pipe section which had had the interior pipe coating removed for inspection.
The licensee acknowledged that based on the age and service of this carbon steel piping, the
pitting could be an indication of initial deterioration of the inner pipe wall coating. The
licensee noted that these issues have been previously discussed and have contributed to their
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institution of a site-wide underground piping inspection program developed in 1990, i
On December 9,1992, the licensee identified a hole in the service water line downstream of the reactor building closed cooling water (RBCCW) system heat exchangers. The hole was at the inner arc of a piping elbow located just inside the reactor building. The piping
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configuration produced a low pressure area in the pipe elbow, causing air to be drawn into the line, rather than causing service water to flow out of the hole. The licensee developed a l
plan to inspect other service water elbows and tec connections downstream of the RBCCW
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heat exchangers. The service water piping upstream of the heat exchangers has been subject i
to periodic hydrostatic tests and was, therefore, excluded from the licensee inspection plans.
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A temporary patch was placed over the hole prior to repair. The elbow was removed and replaced during the service water system outage. The inspection of other piping in this area revealed some areas of moderate wall thinning. The licensee suspected that the interior
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coating may have been worn away, possibly due to crosion/ corrosion effects, in these areas,
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i The licensee will inspect these areas again during the 15R refueling outage.
The licensee also examined service water piping at the intake structure during the outage.
Some areas of external pitting were noted on the service water piping in the south side of the intake structure. One pitted area was repaired by welding a 1-inch coupling over the pit.
Four other pitted areas were weld repaired. The outside coatings of the exposed service
water piping were appropriately repaired after completion of the work.
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Ultrasonic inspection was performed on emergency service water (ESW) system piping both
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in the reactor building and the intake structure. Examination areas were strategically selected based on susceptibility to external or internal corrosion. For example, some of the
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examination areas were focused on the discharge side of the normally throttled ESW overboard discharge valves (V-3-87 and V-3-88). These valves are normally throttled to increase ESW pressure in the containment spray heat exchangers to prevent potentially contaminated containment spray flow from entering the ESW system should a tube leak occur.
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As a result of the ESW inspections, two piping elbows (Elbow 0-ESW-2 E38, downstream of the 1-3 containment spray heat exchanger and Elbow 0-ESWl E33, upstream of the 1-1 containment spray heat exchanger) were found to have UT readings below design minimum wall. Both piping elbows were replaced.
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The inspectors concluded that the licensee had appropriately resolved the known service water system leaks and had performed comprehensive inspections of portions of the service water and ESW system piping. Repairs and replacements were completed as required, and areas for future inspection are appropriately established.
i 3.4 Station Blackout Functional Testing On January 12, 1993, the licensee conducted the functional test of the station blackout (SBO)
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raodification. The SBO modification was installed to provide an alternate ac power supply to the site in the event of a loss of offsite power and the failure of onsite backup power supplies. Two 50 MWe combustion turbine (CT) generators are located on the Forked River site near the Oyster Creek switchyard. During the end of the last operating cycle and the current refueling outage, the licensee has installed the SBO transformer, underground power and control cables between the cts and th_e SBO transformer, and power and control cables to a new 4160V circuit breaker in the B 4160V bus that allows SBO tie-in into the plant, power can be provided to the site from either CT through the SBO transformer.
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12 The functional test was conducted by the licensee's startup and test (SU&T) organization.
Support for the testing was also required from the operations department, contract
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electricians, and several Jersey Central Power and Light (JCP&L) organizations. The functional test was divided into synchrontration tests for CT-1 and CT 2 and a black start test
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for both cts. Synchronization testing was performed to verify that the cts were capable of stable operation at low CT output while connected to the energized B 4160V bus. The black start test of both cts was performed to verify that the site could power the B 4160V bus from the cts with sufficient time remaining to power vital loads within one hour. During
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the black start test the system was tested to verify that a large electrical load could be started without a significant transient on the cts. Following the black start test, the SBO transformer was loaded to 10 MVA (megavolt amps) to verify the design capacity of the transformer.
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The inspector attended the pre test briefings conducted on January 11 and 12,1993. During the briefings good descriptions of the test scope, communication requirements,
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responsibilities, and test steps were provided by the lead SU&T engineer and the Director,
Plant Engineering. Questions raised during the briefings were resolved before commencing the test.
During performance of the test, the inspector observed the synchronization and black start testing using CT-1. Communications and control provided by the SU&T engineer were very
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good. Coordination between the operators in the cor. trol room, at the local SBO control
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panel, and at CT-1 was very good. Several discrepancies were identified by the licensee during the testing observed by the inspector. At the local SBO control panel in the 4160V switch gear room, the SBO transformer output KW meter was reading downscale low.
Shortly after the SBO transformer was energized to 10 MVA using CT-1, the differential current transformer for CT-2 caused the SBO breaker located in the B 4160V breaker cubicle
to trip.
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l The licensee had identified and repaired the problem with the SBO transformer output KW meter before starting the black start test on CT-1. The problem was due to incorrect wiring of the meter. The licensee attributed the CT-2 current transformer causing the SBO 4160V
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breaker to trip to a high resistance contact on the current transformer bypass circuitry.
When a differential current was sensed between the current transformer on the output breaker
for CT-2 and the current transformer on the SBO breaker, the protective circuitry tripped the SBO 4160V breaker. The licensee secured from the test following the SBO breaker trip to determine the cause and develop corrective actions, The licensee performed the verification of the SBO transformer ratings following the black start test of Cr-2. The current
transformer on the output breaker of CT 1 was temporarily jumpered out during testing of CT-2. The licensee is evaluating long-term corrective actions for the deficiencies identified
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during the functional test.
Based on the inspector's observations, the control of the SBO functional test was very well performed. Communication and coordination between Oyster Creek personnel and JCP&L
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personnel responsible for starting the cts were very good. During the timed portion of the black start test for CT-1, the licensee demonstrated that a CT could be secured from the offsite grid, coast down, restart, and energize the B 4160V bus within about 35 minutes from a loss of offsite power. This provides sufficient time for plant operators to energize vital loads within an hour. 'n oughout the portions of the test observed by the inspector, CT 1 performance was stable. When the recirculation motor-generator was started during the black start test of CT-1, the SBO system easily provided the required starting power.
Overall, the inspector concluded that the SBO modification functional test demonstrated the ability of the system to provide an alternate ac power source to the Oyster Creek site.
3.5 Reactor Water Cleanup Valve Electrical Testing On January 4,1993, the inspector observed motor operated valve analysis and test system (MOVATS) testing on th. n, nerative heat exchanger discharge valve for the reactor water cleanup (RWCU) system
, V-16-61. The work was controlled using job order number
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(10#) 43823 and procedur A100-GME-3918.54, revision 2, " Motor Operated Valve Testing Using MOVATS 3000 System."
The inspector reviewed JO# 43823 and procedure A100-GME-3918.54, and questioned the contract technician performing the work and an electrical supuvisor observing the work.
The job package contained adequate precautions and instructions for performing the work.
The necessary approvals and concurrences were obtained before the work started. Both the contract technician and the electrical supervisor were familiar with the procedural requirements and the equipment used to conduct the MOVATS testing. Minor discrepancies in the Limitorque operator response characteristics were identified by the contract technician and the appropriate engineering assistance was requested before additional testing was conducted.
Overall, the inspector concluded that MOVATS testing of V-16-61 was well controlled and
conducted.
4.0 ENGINEERING AND TECHNICAL SUPPORT (71707,40500)
4.1 Recirculation Loop Safe End Boat Sample On December 27,1992, an apparent weld defect was found during ultrasonic testing (UT) of the discharge safe end of the "D" recirculation loop. The defect was ultimately determined to be a sample area which had been weld repaired in 1968.
The Oyster Creek recirculation loop discharge safe ends are furnace sensitized type 304 stainless steel. The safe ends are periodically examined for indications of intergrar.ular stress i
corrosion cracking (IGSCC) due to suspected higher IGSCC sensitivity from the furnace sensitization of the material. The General Electric (GE) examination of the portion of the
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"D" recirculation loop discharge safe end near the reactor vessel nozzle revealed a deep
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defect (about 45% through wall) measuring 0.3 inches circumferentially by 0.9 inches axially by 0.875 inches deep. The normal safe end thickness in this area is 1.625 inches, excluding the 0.22 inch ID cladding thickness. De defect was located about 2 inches away from the safe end-to-nozzle weld.
GE initially suspected IGSCC due to the defect configuration and performed an evaluation based on ASME Section XI, Article IWB-3MO. The defect was treated as a surface flaw for the purpose of the evaluation, even though it did not appear to be surface connected, i.e., in contact with reactor coolant. The GE evaluation concluded that the defect was acceptable for use without repair for one more operating cycle and that it should be reinspected during the 15R refueling outage to assure that crack growth is insignificant.
i During the GE evaluation, GPUN found documentation of a reactor vessel repair program performed in 1968. The documentation noted a " boat" sample which had been taken from
i the "D" recirculation loop discharge safe end in approximately the same location as that denoted by the UT indications. The base metal boat sample, named because of its likeness to
the hull of a boat, was taken to determine whedier any cracking had occurred due to
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sensitization of the metal. GPUN then requested the Electric Power Research Institute
(EPRI) Non Destructive Examination (NDE) Center to do an independent assessment of the UT data. EPRI concluded that the indications were from a weld repair, not IGSCC EPRI i
concluded that (1) the location of the indication was the same as that described for the 1968 boat sample and (2) it was unlikely that the UT indications represented IGSCC EPRI noted that IGSCC propagates through the wall thickness, not parallel to the outside surface. Also, IGSCC is typically detected from the side (UT beam perpendicular to the crack), not from the end (UT beam parallel to crack axis) as was measured with the GE equipment.
GE supplemented its evaluation and concurred with EPRI's conclusion. GPUN has tentatively scheduled reinspection of the "D" recirculation loop discharge safe end for the 15R refueling outage to revalidate that the indications are not IGSCC related, ne inspectors concluded that the licensee had responded appropriately to this material condition issue and that evaluation conclusion; were reasonable and appropriately documented. The indication will be reinspected during the 15R refueling outage.
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4.2 Core Spray Sparger Evaluation During air testing of the core spray system I sparger, the licensee identified a leak in the downcomer between the reactor vessel wall and the sparger inside the reactor vessel shroud.
The leak was located on the side of the downcomer near the reactor vessel wall. Preliminary NRC review of the non-destructive examination (NDE) of this leak is documented in NRC
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inspection report number 50-219/92-24.
As required by Technical Specification (TS) 6.9.3.e, and Oyster Creek operating license condition 2.C.(5), the licensee submitted a report documenting the findings of the 14R outage core spray sparger inspections on January 15, 1993. Before the report was submitted, NRC
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requested a meeting with the licensee to present their findings regarding the leak in the core spray system 1 downcomer. During a meeting held on January 6,1993, the licensee indicated the cause of the failure was a construction weld defect. Based on the discussions held during the meeting, the licensee was requested to provide the NRC with additional analysis discussing what effect the defect had on the structural integrity of the weld and on the performance of the core spray system.
The licensee's supplemental analysis was submitted shortly thereafter. TS 6.9.3.e and operating license condition 2.C.(5) require NRC approval of the licensee's report on core spray sparger inspection before the licensee can restart the unit following the completion of outage work. The NRR review will include assessment of the licensee's evaluation of the weld defect in the core spray system 1 downcomer.
5.0 SECURITY (71707)
During routine tours, inspectors verified that access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded, and isolation zones were free of obstructions. Inspectors examined vital area access points and verified that they were properly locked or guarded and that access control was in accordance with the Security Plan.
6.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (40500)
6.1 Engineered Safety Feature Suetion Strainer Assessment (VIO 50-219/92-25-01)
In response to an event at a Swedish BWR where thermal insulation debris clogged engineered safety feature (ESP) system suction strainers, the inspectors questioned the licensee to determine if Oyster Creek may be susceptible to a similar event. The inspectors also reviewed information concerning the type of insulation material used in the drywell, main ste:un safety / relief valve arrangement, torus suction strainer data, and torus alternate water source availability at Oyster Creek, included in this effort was a review of the design information on the ESF suction strainers contained in the Oyster Creek FSAR. This review identified a discrepancy between the FSAR design information and the as-built information contained on the strainer drawings and in the design report for the replacement torus suction strainers. Table 6.3-3 of the FSAR refers to outer and inner screens associated with the torus suction strainers. The currently installed strainers have only a single screen. The information contained in Table 6.3-3 of the FSAR reflected the design of the original torus section strainers. This original strainer design was reviewed by GPUN in 1984, and at that time it was determined that the original design was not structurally adequate for the fluid dynamic loadings applicable to the Oyster Creek Mark I containment. The original strainers were replaced in 1984 with the current single screen design. The strainer information contained in Table 6.3-3 has not been updated since the 1984 strainer replacemen __
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The inspectors then questioned the licensee as to why the FSAR update process did not
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reflect the change in strainer design. After reviewing the safety evaluation related to the l
1984 suction strainer modification, the licensee noted that the safety evaluation checkoff sheet j
for the then existing version of Technical Functions engineering procedure that controlled
facility changes (EP-016) referred to the original Facility Description and Safety Analysis Report (FDSAR) and not the Updated FSAR. During 1984, GPUN was updating the Oyster Creek FSAR from the old FI'SAR format to the format and content described in NRC Regulatory Guide 1.70. GP: * could not justify why this change had not been included in the 1984 FSAR update and fo. aat change but cited the safety evaluation FDSAR reference as a possible contributor.
The inspectors then reviewed the current FSAR update process to determine whether the
licensee had other opportunities to identify this error. The current FSAR update process
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appropriately provides for the input of changes due to plant modifications and procedure changes through the safety review process. The FSAR update process also includes a
general review of each section of the FSAR by cognizant technical personnel prior to each
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update. The inspectors also reviewed the licensee's description of the design basis reconstitution process and noted that it calls for the identification of discrepancies between
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system design information determined by design basis review and that noted in the FSAR.
Appropriate changes are processed through an FSAR administrator who is responsible for
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coordination of the annual update. This administrator position and the current update process were established in 1990 to establish better GPUN internal control. Prior to that time, the
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Oyster Creek FSAR updates were performed by contractors. The process change was also made, in part, in response to the NRC findings during a 1989 Safety System Functional Inspection (SSFI) of the containment spray / emergency service water system which noted other discrepancies (e.g., net positive suction head (NPSII) limits, pump flow specifications)
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between system design and information provided in the FSAR.
Based on the current FSAR update process, the inspectors concluded that the licensee has had
five opportunities since 1990 to identify this discrepancy and submit a change to the FSAR.
Since the torus suction strainers feed a common header for both the containment spray and i
core spray system, the results of their design basis document (DBD) review should have identified this error. The containment spray DBD, the first in the Oyster Creek program, was completed in 1989. The core spray DBD was completed in mid-1992. Also, since 1990, there have been three pre-FSAR update general t.,,hnical reviews of the containment spray and core spray systems. The licensee's failure to change the FSAR is a violation of 10 CFR 50.71 (e) (VIO 50-219/92-25-01). The licensee is in the process of developing an FSAR change request to reflect the current design of the torus suction strainers.
6.2 Process Re-engineering Program Update in August 1991, GPUN initiated a program to re-engineer the way certain activities are i
conducted to improve performance. This process re-engineering program (PREP) was
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intended to reevaluate and correct overly complicated processes without compromising
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safety. At this time, four initiatives have been chosen for evaluation. They are (1)
equipment control; (2) project management; (3) planning and resource allocation; and (4)
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physical work processes. The status of each initiative is as follows:
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Equipment control implementation of the new Oyster Creek equipment control procedure began in August 1992.
The major change to this process involved the training and qualification of more personnel to perform equipment tagging activities. Previously, these activities were performed only by operations department personnel. While operations is still responsible for ensuring that the equipment has been tagged and positioned appropriately, trained personnel from other departments can develop tagging requests, hang the tags, and accept responsibility for the equipment outage. The computerized tagging system was also modified to accommodate process changes. A further enhancement of the new process was implemented during the 14R refueling outage for system outages. Those personnel who had been assigned as system i
outage coordinators for systems taken out of service for maintenance were also assigned i
overall equipment tagging responsibilities during the maintenance and testing efforts. Since j
its implementation, the process has worked well and the reduction of the resource burden on the operations department has been evident. The success of this program has been evidenced by the small number of equipment control issues occurring during the 14R outage.
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Project Management
The intent of this initiative was to streamline the process through which major projects are idertified, funded, designed, scheduled, and implemented. In the past, many problems with and delays in the implementation of major projects or modifications have occurred due to
poor estimates for cost and schedule, cumbersome review and approval processes, mid-
project scope changes, collateral duties of involved personnel, and turnover difficulties. The PREP effort focused on defining a project management team that includes representation from all groups affected by the project, from the initiator to the end user, so that pertinent personnel are providing input during all phases of the project.
A key factor in this PREP initiative is the enhancement of the system engineer concept. The system engineers will be an integral part of the teams assigned to each major project. Oyster Creek has had system engineers onsite since 1988. However, the system engineering aspects of these positions have often been diverted due to collateral duties involving response to onsite problems. The new process will bring seven additional engineers to the site. The onsite engineering staff will then be split into system engineers and plant engineers. The
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system engineers will be responsible for system overview and participation in project teams, while the plant engineers will provide support for day-to-day plant issues. The new organization will be formally implemented after the 14R outage. The system engineers will report to GPUN Technical Functions. The co-location of engineering personnel, project managers, planners and estimators, and construction managers will also occur after the 14R outage.
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18 During the 14R outage, two pilot projects (hardened vent, valve modifications) were implemented by way of the new project management process. While these projects appear to have been accomplished fairly effectively, the licensec will not complete its evaluation of the l
success of the pilot projects until after the outage.
Future efforts for this PREP initiative are the development of a procedure that will provide guidance for a " graded approach" for new projects. This effort stemmed from the PREP
team's acknowledgement that all projects may not require use of the entire process to be accomplished effectively, i.e., that simple projects should be done simply. This guidance is projected to be implemented by mid-1993.
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Planninc and Resource Allocation
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The intent of this PREP initiative was to develop and implement a better strategic planning process to more proactively assess budgeting and resource needs for future major
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j maintenance, modiSation, and testing activities. A major goal of this initiative was to provide a process that would define appropriate future work and needed support for the long-term with contingencies to effectively accommodate emerging work. The initial implementation phase of this process began just prior to the 14R refueling outage.
The process will involve the development of a multi-year plan. The system enginects will input to the process by providing scope, estimates, and cost benefits for proposed activities.
These inputs will be evaluated by a group of long range planning " coordinators" who will decide whether and when the proposed activity will fit into the multi year plan. The majority of these coordinators are site management personnel. This is a change from the prior i
decision making process for future projects which primarily involved corporate personnel.
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4.
Physical Work Processes The intent of this initiative was to identify and correct inefficiencies in the ways that work is accomplished at the site from work planning to closcout. The initial diagnostic phase of this effort has been completed. This has included a compilation of data from several workshops mvolving all worker levels at which ideas and opinions were solicited regarding work process problems. The PREP team assigned to this effort has cMegorized the workshop suggestions
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into related areas (planning, materials, scheduling, problem identification, management interface, other general job delay issues). The PREP team will reconvene after the 14R outage for several months to assess potential changes to current work processes and propose implementation schedules. An implementation team will then be assigned to develop guidance and provide oversight for the agreed upon changes.
6.3 Quality Assurance Monitoring of Equipment Operator Rounds On July 15,1992, operations quality assurance (OQA) initiated a special effort to observe
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equipment operator (EO) plant tours and logkeeping. This monitoring effort was initiated by i
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OQA at the request of senior plant management to verify the effectiveness of corrective actions taken after instances of incomplete EO plant tours were noted in early 1992. From
July 1992 to November 1992, OQA monitoring personnel accompanied EOs on about 50
plant tours to assess their knowledge of assigned tasks and of the performance standards and i
management expectations associated with the EO tours. The tour accompaniments v ere scheduled so as to cover all shifts, shift crews, and site buildings and included backshift and weekend tours. OQA kept operations department management informed of the tour observation findings throughout the effort.
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l Overall, OQA found the EOs to be knowledgeable and professional. For the most part, the
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EOs demonstrated sufficient knowledge of the established operations department work standards for plant tours and logkeeping. No significant performance problems were noted.
However, OQA did identify a few tour items which were confusing to the EOs, Specifically, a few EOs were not sure of the proper way to determine oil levels on the main transformers, while a few other EOs were uncertain of the method for determining the operability of the startup transformer cooling fans (two switches need to be operated to do this). Operetions department management is developing an on the-job training (OJT) lesson plan to address
these issues. This OJT training will be completed prior to startup from the 14R refueling outage. Some other general tour implementation issues, identified by QA, have been I
adequately responded to by the operations department.
After the 14R outage OQA will resume these efforts by performing about five EO tour
accompaniments per month. OQA will also do periodic tour accompaniments with chemistry and radiological controls technicians. Overall, the inspectors concluded that the OQA efforts in this area were aggressive and performance-based. Some valid questions were brought out as a result of the tour observations, and the operations department responded adequately to them.
7.0 REVIEW OF PREVIOUSLY OPENED ITEMS (92701,92702)
i (Undate) URI 50-219/92-18-01 Reactor Water Level Mismatches for Cold Reference Leg Instrumentation. An announced safety inspection conducted on August 25 to 27,1992,
(Report No. 50-219/92-18) reviewed the facility's ability to respond to the recent reactor water level instrument safety concern. The facility's response to the General Electric Information Letter, SIL No. 470, dated September 16, 1988, was not thorough. Specifically, the facility did not document the exact slope of the cold reference leg reactor water level instrumentation or account for the effect of RPV heatup on the "B" GEMAC level indication, even though plant personnel questioned the water level instrument accuracy.
The regional and resident inspectors conducted a reactor water level reference leg instrument line inspection inside the drywell. The inspection included the following:
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confirm that instrument lines have a downward slope (from the reference leg
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condensing chamber back to the reactor vessel tap) of at least 1/2 inch per j
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confirm that structural supports do not interfere with condensing chamber
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movement, of up to three inches, as the RPV expands during heatup; l
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confirm that there are no points in the steam leg to the condensing chamber that are lower than the leg's RPV nozzle; and
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determine if the reference leg was properly insulated from the RPV nozzle to the condensing chamber.
The review also focused on a site specific problem: the reason for the "B" GEMAC reactor water level indicator reading 5 to 10 inches higher than the "A" GEMAC and Yarway indicators de@g power operation.
The inspectors measured the reference leg slope at three different pipe locations (Attachment 1). The readings were taken with the plant in cold shutdown. The "A"
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GEMAC reference leg slope (IA15A) was approximately 1.3"/ft and the "B" (IAISB) was 0.8"/ft. Both measurements provide significant margin to the GE SIL No. 470 requirement of 0.5"/ft slope from the RPV up to the condensing chamber. The above readings could change when the plant returns to rated temperature and pressure. The walkdown of the
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reference leg line confirmed that there were no pointa in the steam leg to the condensing
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chamber that are lower than the RPV nozzle.
The reference leg pipe runs were measured from the RPV nozzle to the point where the pipe
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exited the drywell wall. There was one noticeable difference between the "A" and "B"
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GEMAC reference legs. The "B" GEMAC instrument line contained a 12-inch thermocouple support, close to the condensing chamber, that was mounted to a rigid pipe support attached to the drywell wall. The "A" GEMAC instrument line contained a 1/2-inch rigid pipe
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support. The longer rigid support on the "B" instrument line could prevent the "B" GEMAC condensing chamber from moving upward as the reactor vessel expands during a plant heatup. The long rigid support could result in the reduction of the "B" GEMAC sensing line
slope below the minimum value of 0.5"/ft. The additional stiffness in the sensing line caused
by the thermocouple bracket could contribute to the "B" GEMAC level indicator reading 5 to 10 inches higher than the "A" GEMAC and Yarway indicators during power operation. The configuration of the "B" GEMAC tensing line was identified to the licensee, along with the inspectors' concern that the thermocouple bracket may be contributing to the indicated level differences between the "B" GEMAC and other level indications. The licensee was evaluating this issue at the end of the inspection period.
There was no insulation on either the "A" or "B" GEMAC reference leg instrument lines.
The lack of insulation could be attributed to work in progress for the reference leg
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instrument lines. Ilowever, based on prior resident inspector tours of the drywell, it was unclear if the sensing lines had ever been insulated. The inspectors questioned the licensee j
on this issue. The licensee was evaluating this issue at the end of the inspection period.
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The inspectors' reactor water level instrumentation reference leg walkdown concluded that i
the slope was adequate for the cold conditions of the plant. Due to the foot long rigid bracket on the "B" GEMAC, it is possible that the slope could drop below thc minimum 1/2 inch /ft for the "B" GEMAC sensing line. The "B" GEMAC reference leg rigid thermocouple bracket was being evaluated by the licensee to determine if this condition contributes to the known 5 to 10-inch high level indication mismatch.
This item will remain open pending the licensee's review of the GEMAC sensing line
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configuration with regards to GE SIL No. 470, licensee evaluation of the effects of the rigid
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thermocouple bracket on the "B" GEMAC sensing line, licensee evaluation of the lack of insulation on the sensing lines, and NRC review of licensec activities.
(Closed) Unresolved item 50-219/89-81-01. NRC Augmented Inspection Team (AIT)
Inspection Report 50-219/89-81 reported that the Oyster Creek Technical Specification (TS)
Table 3.1.1, " Protective Instrumentation Requirement'," listed two trip systems as the minimum number of operable systems required for the low condenser vacuum trip function.
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In this table, the minimum number of instrument channels required per operable channel was also two. The report concluded that the TS table did not reflect the as-built design of the
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condenser vacuum instrument channel considering the Standard TS definition of
" instrument."
Oyster Creek's low vacuum scram instrument logic was designed so that either vacuum trip
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system VT-1 of VT-2 is required to be operable for the scram function to operate. Each trip-system was designed with three bellows instrument channels. All three channels were required to be operable for the trip system to be operable. The licensee considered that, by definition, the TS table reflected the number of vacuum trip system limit switches required to be operable.
The licensee subsequently reassessed the design objectives of the low condenser ucuum scram function and provided clarification for the definition of " trip system" and " bellows instrument system." A TS change request was submitted in August 1992 to more accurately reflect the as-built design of the main condenser vacuum trip system. The proposed change revised the low condenser vacuum trip system operability requirements to require a minimum of one trip system and three instrument channels per operable trip system. This will ensure that vacuum is being sensed in each section of the condenser.
The licensee had also considered removing the condenser vacuum reactor scram function
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from the TS altogether because this trip was not considered in the safety analysis and did not effect fuel cladding integrity or reactor pressure boundary safety limits. However, for i
purposes of turbine protection, the licensee decided that maintaining this function in the TS
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as a backup for the turbine trip on low vacuum was more appropriate. Maintaining the condenser vacuum trip system operable in accordance with the proposed revited TS requirements will assure that vacuum is being sensed in each condenser section, precluding potential turbine damage if the trip were not to occur. The inspector also reviewed
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surveillance procedure 619.3.004, " Condenser Low Vacuum Calibration and Test," Revision
15, dated May 27,1991, and verified that it appropriately tested the as-designed actuation criteria of the reactor trip system. This test will be performed after the completion of turbine work during the 14R refueling outage. Based on these findings, this item is closed.
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LClosed) Violation 50-219/91-37-02. This violation involved inadequate control of measuring and test equipment (M&TE). The licensee's response to the violation stated that job order i
and M&TE usage procedures would be revised. The revisions were to requite documentation, by the job supervisor, in the job package of M&TE used and presentation of q
l the job package to the calibration laboratory technician before M&TE would be issued.
Also, the computer data base system (GMS2) would be modified to provide a method of tracking which M&TE was used on different components using the M&TE identification
number or the specific plant equipment.
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l The inspector reviewed procedures A000-WMS-1220-08, Revision 7, " Job Order," and A 100-ADM-3053.01, Revision 4, " Calibration and Control of Maintenance, Test, and Inspection Tools, Gauges, and Instruments." Also, the inspector reviewed the changes made
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to the GMS2 system and discussed the changes with the calibration laboratory supervisor.
During the review of the procedures, the inspector noted that new requirements for recording
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the M&TE usage in the job package and presenting the job package to the calibration
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laboratory technician were incorporated. During discussions with the calibration laboratory
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J supervisor, the inspector was provided a demonstration on the ability to retrieve information on M&TE usage from the GMS2 data base. The information contained in the GMS2 data
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base was being updated on a daily basis, using information from the completed job packages.
The inspector has also observed the calibration laboratory technicians request the job package before issuing M&TE on a number of occasions over the last operating cycle and during the
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current refueling outage.
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Implementation of the changes to the GMS2 system was delayed until November 27,1992, i
just before the beginning of the 14R refueling outage. With the increased use of M&TE during the outage, the licensee has had some discrepancies with the incorporation of M&TE
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usage into the GMS2 data base. The licensee continues to monitor the performance of M&TE usage and implementation of the revised procedural requirements.
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The licensee has taken adequate administrative actions to improve the documentation and traceability of M&TE use. Traceability of the M&TE using the GMS2 data base was still in
transition. This may be attributed to the large amount of information that has been input to the system during the 14R refueling outage and initialinexperience in use of the new system.
Monitoring and auditing of the M&TE use records by the licensee's quality control organization have identified the need to improve the implementation of the M&TE controls.
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The inspector concluded that the licensee's changes to the M&TB control program were adequate. However, continued improvement in the implementation of those controls is
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required. The licensee recognizes the need to continue implementation improvements. This
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item is closed.
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LClmed) Unresolved item 50-219/91-80-01. This unresolved item dealt with the licensee's
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assessment of reportability related to a March 9,1991, event during which both emergency diesel generators were unavailable with the plant in a shutdown condition. At the time the licensee stated that because vital power remained available to one safety bus from offsite i
throughout the event, no safety functions were lost and the event was not reportable. While the NRC Augmented Inspection Team (AIT) that responded to the event acknowledged the offsite power availability, they questioned the licensee's reportability determination because
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of Oyster Creek Technical Specincation (TS) requirements related to the standby gas treatmeat system (SGTS).
TS 3.5.B.1 establishes requirements for maintenance of secondary containment integrity
which include SGTS operability. SGTS operability was required during the event because TS 3.5 B.I.c was not satisned, i.e., neither the reactor vessel head nor the drywell head
were in place. TS 3.5.B.I.l(b) denotes those actions to be taken if secondary containment is lost in the refueling mode. These actions, which include the cessation of all activities in the reactor building or spent fuel pool area that could cause a reduction in shutdown margin or a release of radioactive material, were all complied with throughout the event. These are similar to actions noted in TS 3.5.B.3.b. for response to SGTS inoperability in the refueling mode.
While these actions were taken in response to control room personnel declaring SGTS inoperable after the loss of the second EDO, the licensee contends that SGTS was capable of
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performing its intended safety function because of the availability of offsite power. The licensee agreed that by the TS dennition for operability, SGTS was inoperable due to the
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requirement for dinrse power supplies. However, the offsite power saurce enabled SGTS to maintain its speci6ed safety function.
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A plant review group (PRG) meeting was held on December 17,1992, to reassess the
licensee's March 1991 decision based on current guidance on determination of operability and assessment of degraded plant conditions (NRC Generic Letter (GL) 91-18). PRG concluded that SGTS had been inoperable based on the Oyster Creek TS operability deGnition and the NRC GL 91-18 guidance. PRG also concluded that the SGTS safety
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function was met, even though the system was inoperable by TS dennition because all TS actions regarding inoperability of SGTS in the refueling mode were met and because the offsite power feed was available. PRG cited Section 3.3, Specined Functions, of the operability technical guidance provYed in NRC GL 91-18 which states that "... When
system capability is degraded to a point where it cannot perform with reasonable assurance or reliability, the system should be judged inoperable, even if the system could provide the
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specified safety function." Based on the above, PRG concluded that the March 9,1991, event we.s not reportable. Specifically,10 CFR 50.73 (a)(2)(i)(B) did not apply because all TS action statements were met and 10 CFR 50.73 (a)(2)(v)(c) did not apply because SGTS had not lost the ability to perform its safety function. The inspector reviewed NRC GL 91-18,10 CFR 50.73, the Oyster Creek TS sections related to the issue, and attended the PRG
meeting of December 17,1992, and concluded that the March 9,1991, event was not
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reportable. Based on these findings, this item is closed.
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8.0 EXIT MEETINGS AND UNRESOLVED ITEMS (40500,71707)
8.1 Preliminary Inspection Findings A verbal summary of preliminary fm' dings was provided to the senior licensee management on January 21,1992. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this report. The inspection consisted of normal, backshift, and deep bacl' shift inspection; 31 of the direct inspection hours were performed during backshift periods, and 12 of the hours were deep backshift hours.
8.2 Attendance at Management Meetings Conducted by Other NRC Inspectors The resident inspectors attended exit meetings for other inspections conducted as follows:
January 15, 1993 F m rt N o. 50-219/92-24 January 8,1993 Report No. 50-219/93-01 At these meetings the lead inspector discussed preliminary findings with senior GPUN management.
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