IR 05000219/1994007
| ML20029D963 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 05/06/1994 |
| From: | Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20029D962 | List: |
| References | |
| 50-219-94-07, 50-219-94-7, NUDOCS 9405130182 | |
| Download: ML20029D963 (21) | |
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U. S. NUCLEAR REGULATORY COMMISSION l
REGION I
Report No.
94-07 Docket No.
50-219 License No.
DPR-16 Licensee:
GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 Facility Name:
Oyster Creek Nuclear Generating Station Inspection Period:
March 8,1994 - April 18,1994 Inspectors:
Larry Briggs, Senior Resident Inspector Stephen Pindale, Resident Inspector l
6/6' N[
7 Mm
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Approved By:
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'n Rogge, Section$hief Ilate'
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eactor Projects Section 4B Inspection Summary: This inspection report documents the safety inspections conducted during day shift and backshift hours of station activities including: plant operations, maintenance, engineering, plant support, and safety assessment / quality verification. The Executive Summary delineates the inspection findings and conclusions.
9405130192 940506 PDR ADDCK 05000219
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EXECUTIVE SUMMARY Oyster Creek Nuclear Generating Station Report No. 94-07 Plant Operations The unit was operated safely. Overall, plant housekeeping and material condition was very good; specific exceptions included unsecured transient equipment found near safety related eq1pment, and the overall condition of the fire pump house warrants increased management attention. Overall reactor operator response to an automatic reactor shutdown was generally good, however, operators initially misdiagnosed the cause of the transient and the actions to restore reactor level control were somewhat slow. A detailed walkdown of the containment spray / emergency service water system determined that the system was properly aligned, however, specific deficiencies were. identified when comparing the existing configuration to plant drawings for structural supports and surveillance testing of containment spray pump room cooling fans; the configuration control and testing issues are the subject of an unresolved item. Special testing of the feedwater control system was well planned and executed.
Maintenance The maintenance and surveillance testing activities observed during this inspection were conducted safety by knowledgeable personnel. Troubleshooting and repair activities associated with emergency diesel generator problems were well controlled and conducted.
Eneineering The onsite engineering organization properly prioritized and executed work activities. The j
system engineering personnel completed a thorough evaluation following the failure of an isolation condenser valve. A comprehensive evaluation was completed in support of leak repair activities for an unisolable reactor water cleanup valve. The licensee appropriately responded to a 10 CFR Part 21 Report regarding Whiting Cranes.
Plant Support Overall, periodic observation by the inspector of station workers and Radiological Controls (RC) personnel noted proper implementation of radiation controls and protection requirements. RC personnel promptly and thoroughly responded to an event in which a I
station worker received a higher than expected radiation exposure during a periodic condenser bey inspection. The inspectors observed that security program requirements were properly implemented by the licensee.
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Safety Assessment /Ouality Verification The inspector found implementation weaknesses associated with the licensee's heat stress control program; proposed licensee actions to correct the weaknesses were prompt and appropriate. The licensee took appropriate action to implement modifications to stiffen the reactor building roof structure and to correct deficiencies identified during the modifications.
Licensee management proactively elected to maintain the unit in a Cold Shutdown condition for several days following the automatic reactor shutdown so that additional preventive and corrective maintenance activities could be completed.
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TABLE OF CONTENTS Eage EXECUTIVE SUMMARY ii
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1.0 PLANT OPERATIONS (40500, 71707, 71710, 93702)
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1.1 Opera tion s S u m mary................................. I I
1.2 Facility Tours
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1.3 Reactor Scram Due to Component Failure.................... 2 1.4 Engineered Safety Feature System Walkdown (Unresolved Item 50-219/94-07-01)
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1.5 Special Test Of Feedwater System Dynamic Response............. 5 2.0 MAINTENANCE (61726, 62703).............................. 6 2.1 Maintenance Activities................................ 6 2.2 Emergency Diesel Generator Repairs....................... 6 2.3 Surveillance Activities
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l 3.0 ENGINEERING (37828, 40500, 71707).......................... 8
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3.1 Isolation Condenser Valve Stem Failure (Unresolved Item 50-219/93-81-02 Update)
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3.2 Leak Repair of Reactor Water Cleanup System Valve............. 9 3.3 Whiting Crane Part 21 Report...........................
3.4 Inoperable Reactor Coolant Sample Valve (Unresolved Item 50-219/94-07-02).........................................
4.0 PLANT SUPPORT (71707)
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4.1 Radiological Controls................................
4.2 Higher Than Expected Radiation Dose During Weekly Condenser Bay Tour..........................................
4.3 Secu ri ty........................................
5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (40500,71707, 90712/13)
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5.1 Heat Stress Control Program Implementation Weaknesses..........
5.2 Reactor Building Structural Deficiencies
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5.3 Licensee Event Report (LER) and Periodic Report Review.........
6.0 EXIT INTERVIEWS / MEETINGS (40500, 71707)
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6.1 Preliminary Inspection Findings
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6.2 Attendance at Management Meetings
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DETAILS 1.0 PLANT OPERATIONS (40500, 71707, 71710, 93702)
1.1 Operations Summary The unit was operating at 100 percent power at the beginning of this inspection period, and continued to operate at full power until April 5,1994, when the unit automatically shutdown.
The shutdown was caused by a component failure within the feedwater control system. That failure resulted in a high water level condition in the reactor, which generated the turbine trip / reactor scram signal. Oyster Creek operators subsequently placed the unit in Cold Shutdown (reactor coolant system temperature less than 212 degrees F) in order to perform additional maintenance activities. The unit had operated continuously for 413 days since reactor startup from the 14R refueling outage in February 1993.
While the unit was shutdown, GPUN identified that a steam inlet valve for the "B" isolation condenser had failed such that the valve stem had failed and separated from the valve disk.
That valve was repaired and similar isolation condenser valves were inspected to confirm valve stem integrity; no similar conditions were identified.
A reactor startup commenced on April 12, 1994, and the reactor was made critical at 5:17 p.m. The main turbine / generator unit was placed on line on April 13, 1994. The unit operated at full power for the remainder of the inspection period.
1.2 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:
e control room o
intake area e
cable spreading room o
reactor building diesel generator building
turbine building e
e new radwaste building e
vital switchgear rooms e
old radwaste building e
access control points e
transformer yard e
fire pump building Control room activities were found to be well controlled and conducted in a professional manner. The inspectors verified operator knowledge of ongoing plant activities, equipment status, and existing fire watches.
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The inspectors noted that overall housekeeping and material condition of the station was generally very good. However, some areas needed attention. Specifically, the fire pump house was noted as being in poor condition when compared to the station. Several deficiencies were identified and communicated to the Director, Operations and Maintenance (DOM). Examples of deficiencies were, one of the entrance / exit doors had a defective j
latching mechanism and was propped shut with a board, the spill basin under the diesel fire pump fuel oil tank was one third full of water, and building cleanliness was poor. The DOM took action to have the spill basin drained and has had the fire pump building placed on the
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Station Services routine housekeeping activity schedule, which is performed biweekly. The inspectors noted that routine NRC tours will also be conducted to monitor repair, cleanup and building maintenance activities.
During a routine tour of the plant, the inspector identified that scaffolding and other transient equipment was staged close to, and some equipment was leaning on, a safety related battery charger. None of the equipment was locked in place or otherwise secured. The inspector informed the DOM of the observations; immediate corrective actions were taken. However, after the inspection period, the inspector noted that other equipment (electrical breakers and a large tool box) were stored in the same area, near the battery charger. That equipment was likewise unsecured. The inspector again informed the DOM on April 22,1994, of the concern, who stated that corrective action would be initiated. While these specific deficiencies were addressed after the inspector informed station management, the inspector expressed a concern that the licensee may not be properly controlling transient equipment located near safety related components. The inspection in this area is continuing, and will be
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completed during the next resident inspection.
1.3 Reactor Scram Due to Component Failure At 3:50 p.m., on April 5,1994, an automatic turbine trip and reactor shutdown (scram), due to high reactor water level, occurred while operating at 100% power. The reactor water high level condition was the result of a component failure within the feedwater control system (FCS). Plant response to the scram was as per design. Operator response to the scram was generally good. However, some operator actions were not effective or timely, particularly those associated with initial response to the transient (prior to the scram) and the
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post-scram reactor water level control. Specifically, a second reactor scram occurred at about 4:10 p.m. due to low reactor water level. The plant was stabilized, and the operators subsequently initiated a reactor cooldown to Cold Shutdown per station procedures. The licensee reported this event to the NRC in accordance with 10 CFR 50.72 reporting requirements.
The component that failed was a proportional amplifier module in the FCS. The failure caused both steam flow channels to fail upscale (high). The FCS responded to the false increased steam demand by rapidly increasing feedwater (FW) flow. The FW flow increased until the FCS runout protection circuit became the controlling circuit. The runout protection limits FW flow to preset maximum values to prevent FW pump runout conditions from occurrin l I
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A control room reactor operator (RO) first recognized the transient condition shortly after the FW pump runout protection circuit actuated when he observed that all three FW pump runout
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protection lamps were illuminated. It should be noted that there is no audible alarm I
associated with the FW pump runout protection actuation, although the licensee stated that there used to be an audible alarm that had been removed via a modification. While l
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responding to the transient condition, a second RO was checking control room indications, and noticed that the indicated reactor power level on the computer screen hao increased by about 10% (to 2118 MW,). The RO suspected that the power increase was due to a recurrence of previously experienced reactor recirculation (RR) control system problems, and proceeded to reduce RR pump speed on the master controller for all five RR pumps; RR flow was reduced by about 20%.
l It was later determined that the computer-indicated power was falsely high, and was due to the use of FW flow as an input to the thermal power calculation. FW flow is a main input to the calculated heat balance. Actual reactor power, as read from the average power range monitor system had increased by about 5% before the operators reduced RR flow.
The operators noted the continued reactor level increase and considered either switching the FCS from three-element to single element control or placing the FCS from automatic to manual. Either action should have minimized the transient effects. However, before either action could be taken, the reactor automatically scrammed after reaching the high level l
setpoint. The total time from when the FW pumps went to a runout condition until the reactor scram was about 30 seconds.
Following the scram, reactor pressure increased due to the rapid turbine stop valve closure.
No electromatic relief valves lifted, however, reactor pressure was momentarily high enough (1049 psig) to activate the RR pump Anticipated Transient Without Scram (ATWS) trip logic (1050 +/- 3 psig). All five RR pumps tripped. The isolation condensers, which also actuate at the same pressure, did not actuate because a sustained (1.5 seconds) signal must exist for actuation.
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l The ROs stopped all three FW pumps and the operating control rod drive (CRD) pump in an l
effort to reduce reactor water level to normal. However, the operators did not re-establish i
reactor vessel makeup early enough as level continued to drop. Consequently, even though one FW pump and one CRD pump were ultimately restarted, a low reactor level scram occurred at about 4:10 p.m. Level was subsequently maintained within the normal band.
Due to the trip of all five RR pumps, the unit had to be placed in a Cold Shutdown condition. That is because Technical Specifications require than an idle RR loop cannot be started unless the temperature of the reactor coolant within the idle loop is within 50 F of the reactor coolant temperature. Since Oyster Creek does not currently have a reactor bottom head temperature indication, the 50*F differential temperature cannot be verified. As a result, operators are required to reach Cold Shutdown before a RR pump can be restarted.
The purpose of the restriction is to prevent excessive thermal stresses on reactor component.
The licensee is evaluating possible modifications to prevent similar future situations, such as 1) installing the necessary temperature devices at the reactor bottom head area and/or 2)
providing a time delay to the ATWS RR pump trip so that the ATWS trip will only occur i
when a sustained condition exists.
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The resident inspectors responded to the control room immediately following the high level scram. The inspector observed operator post-scram performance, reviewed plant data and logs, interviewed operations shift peisonnel, and observed portions of the Post-Transient Review Group (PTRG) evaluation. The inspector concluded that the operator response was generally good. The RO promptly recognized the illuminated FW pump runout light (no audible alarm). However, the transient was initially misdiagnosed as a RR control system problem, even though the FW pump runout lights were recognized. Also, the operators were slow to re-establish makeup flow to the reactor. As a result, the second scram (low reactor water level) was experienced.
The inspector concluded that the root cause of the. event was properly identified and corrected. The failed electronic module, which was original plant equipment, was replaced.
In addition, an adjacent original electronic module in the FCS was replaced as a preventive measure. This portion of the FCS is currently planned to be replaced during the upcoming refueling outage (Fall 1994), due to previously identified operational / maintenance concerns.
The PTRG investigation of the event was determined to be timely and effective. The inspector verified that portions of the recommended corrective actions were completed, including observation of a briefing of operating crews regarding lessons learned from the transient.
Following the scram, GPUN station management elected to stay in Cold Shutdown for several days in order to perform additional preventive and corrective maintenance on components which required a unit shutdown to perform the work. The inspector determined that the licensee's decision was prudent and conservative, to the extent that future operational problems may have been prevented or minimized by completing the associated work activities since the plant had operated continuously in excess of 400 days.
1.4 Engineered Safety Feature System Walkdown (Unresolved Item 50-219/94-07-01)
The inspectors conducted a detailed walkdown of the containment spray / emergency service water (CS/ESW) system in order to independently verify the status and operability of the system. This inspection consisted of a review of Technical Specification requirements, FSAR commitments, a full system walkdown of all accessible components (including piping, valves, breakers, and seismic supports), and a comparison with the as-found system alignment and the CS/ESW system operating procedure specified lineu. _ _ _
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The inspectors concluded that the CS/ESW system valves and breakers were properly aligned. However, during the walkdown, several deficiencies or questions were identified and communicated to the responsible system engineer. Those items included numerous seismic supports that were of a different type (rigid instead of hydraulic) than those shown on the system isometric drawings; deficient thread engagement of specific flanged connections; threaded caps identified on drawings that were not installed on several ESW instrument lines; and several other minor deficiencies. In addition, the surveillance procedure did not verify that each CS pump independently starts its associated room cooling fan. Specifically, each of the two CS/ESW trains have two associated CS pumps, and each CS/ESW train has one cooling fan that starts automatically upon a start of either CS pump. However, the surveillance procedure (No. 607.4.004) verifies that each cooling fan starts from'only one of the two associate! CS pumps.
The system engineer responded to the inspector's questions toward the end of the inspection period. Thread engagement concerns were previously identified at Oyster Creek. By memorandum dated October 21,1993, the licensee's engineering organization provided clarification regarding acceptable thread engagement, which was determined to be the stud / bolt extending two threads out of its mating part. The memorandum concluded that existing thread engagements should be considered functional, and should be repaired as the flanges / components are loosened for maintenance or modification. The other concerns were..
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similarly addressed by the licensee. A review of the cooling fan concern is continuing, and the system engineer believes that an evaluation was previously performed, which concluded that the heat load during CS/ESW system operation was such that the cooling fans were not required. The system engineer noted that there were several change notices outstanding
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against the seismic support list drawing but had not been able to obtain copies before the end of the report period. The inspector concluded that additional review was necessary in this area to determine whether there is a significant design control / configuration problem.
Pending further NRC review to determine proper identification of seismic supports (and related design control issues) and the adequacy of cooling fan surveillance testing, this item
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is considered unresolved.
(UNR 50-219/94-07-01)
1.5 Special Test Of Feedwater System Dynamic Response On April 14, 1994, at about 60 percent and 90 percent reactor power, the licensee conducted a special test of the dynamic response of the feedwater control system. The test was conducted under procedure No. Special 93-010, "Special Test of Plant Feedwater Control Dynamic Response," Revision 0, to obtain feed system response time information. The information is planned to be used for the digital feedwater control system modification that is scheduled to be installed during the 15R outage (Fall 1994). The procedure initiated several
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~ inches. The feedwater control system was tested in different modes of level control, with system response time measured until level recovery or when' operator manual actions were
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taken. The tests were successfully completed at 3:25 p.m. on April 14, 1994.
J The inspector cbserved the licensee's pre-test briefing which discussed various aspects of the
test, such as the expected sequence of testing, responsibilities and authorities, test termination criterion, and plant operational safety and control. Part of the testing was observed by the inspector. It was well controlled and proceeded in a slow and deliberate manner. The inspector also reviewed the licensee's safety evaluation for this special test to verify that it was complete and that the test did not constitute an unreviewed safety concern. _ The inspector determined that the safety evaluation was acceptable.
The inspector determined that the planning of the test and procedural development was well
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thought out with appropriate reviews and evaluations. Actual testing was conducted in a
. controlled, safe manner and all personnel involved were knowledgeable of test sequence and
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2.0 MAINTENANCE (61726,62703)
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2.1 Maintenance Activities j
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The inspectors observed selected maintenance activities on safety-related equipment to j
ascertain that the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.
The inspector observed portions of the following activities.
-Job Order 00)
Descriotion i
JO 51159 Repack "B" isolation condenser steam inlet valve V-14-33;
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JO 53369 Troubleshoot and repair No.1 E7G speed control system; JO 53484 Repair "B" isolation condenser steam inlet valve V-14-32.
2.2 Emergency Diesel Generator Repairs On April 4,1994, while performing the emergency diesel generator (EDG) weekly load test (636.4.003) surveillance, the No.1 EDG started and came up to voltage, but frequency went
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to the mechanical high speed stop (about 63 hertz). The EDG would not automatically l
parallel due to the inability to.natch grid frequency. Frequency also could not be controlled in manual.
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The inspector observed troubleshooting activities performed by the EDG system engineer and
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electrical maintenance personnel. The associated activities were discussed and planned prior to troubleshooting (e.g., which voltage. readings to obtain and expected values). The
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troubleshooting activities indicated that the fault was in the " Peaking Load Control Assembly" (called the EG box). The EG box was replaced on April 4,1994. Further tests and adjustments were completed satisfactorily on April 6, following the turbine / reactor trip which occurred on April 5,1994.
The inspector determined that the EDG troubleshooting and repair activities were performed in accordance with approved procedures in a controlled and planned manner.
2.3 Surveillance Activities The inspectors performed technical procedure reviews, witnessed in-progress surveillance i
testing, and reviewed completed surveillance packages. The inspectors reviewed the following surveillance test procedures and observed portions of the associated testing activities:
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Procedure No.
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620.4.002 Average Power Range Monitor - Front Panel Check 652.4.002 Instrument Air System Isolation Valve to the Drywell -
Operability and Inservice Test
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602.4.002 Main Steam Isolation Valve Closure and Inservice Test
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607.4.004 Containment Spray and Emergency Service Water System 1 Pump Operability and Inservice Test 607.4.005 Containment Spray and Emergency Service Water System 2 Pump Operability and Inservice Test The inspectors noted that a properly approved procedure was in use, approval was obtained and prerequisites satisfied prior to beginning the test, test instrumentation was properly
calibrated and used, radiological practices were adequate, technical specifications were satisfied, and personnel performing the tests were qualified and knowledgeable about the test procedure.
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-S 3.0 ENGINEERING (37828,40500,71707)
3.1 Isolation Condenser Valve Stem Failure (Unresolved item 50-219/93-81-02
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Update)
- l On April 7,1994, the licensee found that the valve stem for isolation condenser (IC) valve V-14-32 had separated from the valve disk. The valve is the inboard (closest to the IC) of the two steam inlet isolation valves for the "B" IC Station personnel were in the process 'of-preparing to place the valve on its backseat for repacking activities. 'During an attempt to remotely open the valve, an unusual noise was noted by personnel in the area. An operator subsequently attempted to manually backseat the valve, and noticed that the stem rotated as -
he turned the handwheel. At that point, all operation of V-14-32 was discontinued'pending further investigation.
V-14-32 is a motor operated valve that is horizontally mounted. The licensee has experienced several packing leakage problems with this and other similar IC valves. NRC -
Inspection reports 50-219/93-29 and 50-219/93-81 reviewed related issues. Due to the valve packing leakage problems, several of the four steam IC valves (two for each IC) were
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required to be placed on the backseat to minimize steam leakage through the valve packing.
The licensee's evaluation for the IC steam valves had determined that the packing leakage occurs due to the weight of the disc and stem bearing on the valve packing while the valves are in the open position. Additional work, including corrective work and modifications to be performed by the valve vendor, has been planned for the upcoming refueling outage (Fall 1994). During the current operating cycle (since February 1993), the V-14-32 valve has been backseated five times. Backseating of other IC steam valves is as follows:
e V-14-33 ("B" IC); 4 times e
V-14-30 ("A" IC); 13 times e
V-14-31 ("A" IC); 1 time.
Following the failure of the V-14-32 valve stem, the licensee initiated several actions. The V-14-32 valve stem, valve bonnet, and the disc wedge assembly were replaced. Upon disassembly, the valve disc was in the closed position. The failed stem was sent to an-independent laboratory for failure analysis. The licensee also performed ultrasonic testing on the remaining three steam IC valves and two of the four condensate IC valves to detect similar stem defects; none were identified. A modification was also implemented for all four steam valve motor operators. Specifically, the tripper fingers were removed in order to -
allow " soft" manual backseating. Previously, manually backseating was not performed due to the potential for the tripper fingers to fail and consequently prevent subsequent remote operation. After the modification was completed, the licensee developed a procedure to provide specific guidance for performing manual backseating.
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l The licensee performed an operability determination following this event. Based upon
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available surveillance test and other operational data, the licensee concluded that the valve was left in its required open position during the last operability test (March 24,1994), and was capable of performing its design safety function. That function is to close in the event that an IC line break were to occur.
The inspector reviewed the licensee's actions, including the ultrasonic testing, corrective maintenance, and followup evaluations, and concluded that the licensee's actions were appropriate. Although the preliminary information from the laboratory indicated that the valve stem failure was a low cycle fatigue failure, a final report was not yet submitted. The licensee's actions taken in response to this event were appropriate. However, the final results of the stem failure analysis may reveal new or unique information relative to the fai'ure mechanism of the valve stem. As such, the scope of existing Unresolved Item 50-219/93-81-02 will be expanded to track the completion of the failure analysis.
3.2 Leak Repair of Reactor Water Cleanup System Valve During a tour of the drywell on April 6,1994, the licensee identified a leak of about 0.5 gpm on valve V-16-133. This valve is a six inch pressure seal gate valve. It is a manually operated, normally open valve located in the drywell and is not accessible during plant operation. This valve is also the first isolation valve for the reactor water cleanup (RWCU)
system and is therefore not isolable from the reactor recirculation system. The valve was successfully leak repaired on April 8,1994.
The work was performed under the administrative control of procedure A000-WMS-7160.02, Revision 3, "On-Line Sealing Compounds," which provides overall guidance and engineering evaluation requirements and considerations such as volume of sealant, chemical content of sealant, component stress due to injection, and other limiting factors. The technical direction was provided by Job Order 53440 and Leak Repair Procedure NP-2142\\NP-2144, which is a vendor procedure that was reviewed and approved by the licensee's engineering department.
Engineering Evaluation No.121-94 was performed which verified the contractor's void calculations, determined the maximum sealant to be used, maximum injection pressure, valve yoke to body and yoke to bonnet bolt strength, and where the sealant would be injected. A use permit (No. 940408.3) was signed by chemistry authorizing use of this particular sealant
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for this application. The corporate engineers evaluated the seismic impact of adding the
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weight of the sealant, sealant injection valves and a leakage collection device to the valve. It was determined to be acceptable.
The sealant was injected into the valve body to fill the void above the thrust ring and the
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spacer by drilling and tapping two injection ports 180 degrees apart half way between the valve bonnet and the knock-out ports. By injecting above the pressure seal, the possibility of getting sealant into the reactor recirculation system was reduced. The knock-out ports were
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also drilled and tapped and injected with sealant. The injection was made on April 8 and successfully stopped the leak. The valve was again inspected at 1000 psig and 545 *F, it continued to be leak tight.
The inspector determined that the licensee had performed a comprehensive evaluation and developed a detailed plan to perform the leak repair on V-16-133. The approved procedure ensured that valve and/or system damage potential was minimal by injecting above the valve seal and that injection pressure limits were well below bolt strength limits.
3.3 Whiting Crane Part 21 Report On Wednesday, March 2,1994, the NRC was notified that Whiting Cranes with certain serial numbers had been identified as having significant over-stress conditions on bolted connection points of the trolley main hoist components. Whiting recommended that use of the cranes of a similar design discontinue use until repairs could be made. Oyster Creek was one of the facilities specifically noted on the report to the NRC. On March 8,1994, the inspector obtained a copy of the Part 21 report from the licensee. The copy provided to the inspector noted (by the license) that the crane serial number (10044) was in fact at the Three Mile Island Unit 2 site. To ensure that the crane at Oyster Creek was not affected the inspector obtained the serial number of the reactor building crane (9292) and called Whiting
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Crane. The serial number of the Oyster Creek crane was not among those listed.
The inspector determined that the licensee had promptly identified the correct location of the possibly defective crane and that Oyster Creek was not affected by the Part 21 report.
3.4 Inoperable Reactor Coolant Sample Valve (Unresolved Item 50-219/94-07-02)
Since early February 1994, the " preferred" reactor coolant sample flow path has been out of service due to a failed sample system valve (No. V-24-29). During a surveillance test on February 4,1994 (procedure No. 678.4.002), V-24-29 failed to properly operate. The valve is the reactor sample inboard containment isolation valve. Following the surveillance test failure, V-24-29 was declared inoperable, and the action requirements of Technical Specification 3.5.3 were satisfied; the outboard sample valve (No. V-24-30) was closed and electrically de-energized. Both valves are air operated, controlled by 120 volt AC solenoid valves.
The licensee attempted the surveillance test again on February 10, 1994, however, they were unable to establish flow at the sample sink through the valve. The licensee suspected that V-24-29 was stuck closed. Both V-24-29 and V-24-30 control switches were placed in the closed position and the valves electrically disabled (closed position). Reactor chemistry samples were obtained via an alternate flowpath from the reactor water cleanup (RWCU)
syste.
During this inspection period, the licensee was pursuing the development of a special test
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procedure to verify that V-24-29 was closed, so that only V-24-29 would be required to be de-energized. In that configuration, V-24-30 could be opened to obtain a reactor coolant
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sample from the standby liquid control (SLC) system; the SLC sample line connects in between V-24-29 and V-24-30. The licensee wanted to provide that sampling alternative to support a planned RWCU system outage.
While efforts were continuing toward conducting the special test, the reactor automatically shutdown on April 5,1994. Since V-24-29 is located in the drywell, and the plant
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subsequently proceeded to Cold Shutdown, the licensee had the opportunity to enter the drywell and complete repairs to the failed valve.
The licensee replaced the failed solenoid valve while the unit was shutdown. The valve inspection revealed that V-24-29 was closed and that the existing solenoid valve was the cause for the failure. The licensee stated that the cause of the failure was related to the solenoid becoming wet. A corrective change (minor modification) was then developed, which replaced the existing " general purpose" solenoid valve with a nuclear qualified valve with a better moisture proof enclosure.
The inspector monitored the licensee's activities associated with pursuing alternative sample flowpaths, the repair of the solenoid valve, and the required qualification of the components.
l The inspector concluded that the licensee was proactive in their pursuit of developing an alternative sample flowpath in the event of a loss of the RWCU flowpath. While reviewing
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the corrective change technical evaluation, the inspector noted that both V-24-29 and V-24-30 are containment isolation valves. As such, they are required to close upon specific isolation signals. However, the solenoid valves are not required to be environmentally qualified (EQ)
as per the licensee's existing component database. The solenoid valves are normally i
energized, and must de-energize to vent air from the valve diaphragm in order to fulfill its nuclear safety related containment isolation function. The licensee informed the inspector that the replacement solenoid valve is an EQ component, although not required by their program.
The inspector questioned the licensee regarding any existing evaluation for the solenoid valves that may support the basis for not being EQ components. Pending receipt of the associated evaluation (s), and subsequent inspector review (including a review to determine whether this condition was reportable), this item is unresolved.
Unresolved Item 50-219/94-07-02)
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4.0 PLANT SUPPORT (71707)
4.1 Radiological Controls During entry to and exit from the radiologically controlled area (RCA), the inspectors verified 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. During periodic plant tours, the inspectors verified that posted extended Radiation Work Permits
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(RWPs) and survey status boards were current and accurate. The inspectors observed activities in the RCA and verified that personnel were complying with the requirements of j
applicable RWPs and that workers were aware of the radiological conditions in the area.
4.2 IIigher Than Expected Radiation Dose During Weekly Condenser Bay Tour On March 21, 1994, while conducting a weekly tour in the condenser bay, an equipment operator (EO) received more than the normal radiation dose for such a tour. Workers normally receive about 60 mrem during the 15-20 minute tour. In this case, however, the
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tour length was roughly 35 minutes and the EO received 256 mrem, as indicated on his
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electronic self reading dosimeter (ESRD). Since the individual received more them 100 mrem in excess of the planned exposure, the Radiological Controls (RC) department conducted a Radiological Incident Report (RIR) and critique of the event. No NRC radiation dose standards were exceeded.
The condenser bay is a high radiation area (HRA) and a contaminated area. The EO donned the appropriate protective clothing for the entry, as specified in Radiation Work Permit (RWP) No. 940020. The RC technician, who was monitoring the job, became concerned about the EO after roughly 25 minutes. The RC technician then dressed in the appropriate
protective clothing and entered the area to locate the EO. After the technician located the
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EO, they both proceeded to the step-off pad for the area, at which time, both workers noticed that the EO's ESRD audible alarm had actuated.
The EO was wearing his ESRD underneath his protective clothing, and therefore could not read the instrument. In addition, the condenser bay and heater bay areas are both noisy such that the EO did not know that the ESRD was alarming; the alarm setpoint was a dose of 100 mrem. After the EO removed his protective clothing, the ESRD reading was observed to be 256 mrem.
The licensee's investigation concluded that the EO " improperly operated or misused" the ESRD. Specifically, the EO wore the ESRD at the waist and undemeath his protective clothing, preventing him from monitoring accumulated dose and making it more difficult to hear the ESRD alarm. Corrective actions included the following:
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o conducting a critique (RIR), to determine root cause; informing all Oyster Creek employees of relevant details of this event;
conducting noise-testing of the ESRD alarms to assure minimum described
levels are achieved; and observing General Employee Training to confirm that proper ESRD placement
is addressed.
Other issues were noted by the licensee. A Group RadCon Supervisor (GRCS) was not present at the pre-job briefing. While this was not considered by the inspectors to be a contributing factor in this event, it was a contributing factor in the May 1993 511 aisle events noted in NRC Inspection Report 50-219/93-07. The inspectors have found no other cases in which the appropriate individuals had not been present at a pre-job briefing and as such there is no indication that a programmatic deficiency exists. However, this was considered a weakness. The GRCS was counseled and Radiological Controls Field Operations stressed the importance of pre-job briefing attendance.
As a result of this incident, the inspector reviewed several procedures to ensure that radiological work plans and associated requirements were written to clearly disseminate management's expectations on proper work conduct and proper development of radiological work plans.
The following procedures were reviewed:
6630-ADM-4110.04, " Radiological Work Process"
6630-ADM-4000.ll, " Rules for Conduct of Radiological Work"
6630-ADM-4010.02, " Conduct of Radiological Engineering" Procedure 6630-ADM-4110.04 is applicable to both radiation workers and those individuals responsible for developing RWPs. The inspector noted that the same procedure section applied to both the workers and the RWP developers, making it dif6 cult to differentiate which instructions applied to which group. This was discussed with the Radiation Protection Manager, who stated that the Radiological Work Process procedure would be subjected to a human performance engineering review with the intent to increase the procedure's utility.
The inspector reviewed this event and found that the RC organization promptly responded to this event. The EO had essentially completed his tour at about the time that the RC technician located him. The EO stated that he did not think that he was in the area for an inordinate amount of time (he had previously performed the tour route). His dose was higher because 1) he was in the HRA for a longer than normal time period, and 2) he spent extra time locating several leaking valves which were located in higher dose rate areas. The inspector concluded that the RC technician responded quickly and appropriately in order to
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determine why the EO was in the area for longer than expected; During the review of this event, the inspector identified some concerns related to the licensee's heat stress program.
See Section 5.1 of this report for further discussion. The inspector concluded that the licensee's overall response and followup for this event were appropriate.
4.3 Security During routine tours, the 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. The 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.
5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (40500,71707,90712/13)
l 5.1 IIcat Stress Control Program Implementation Weaknesses l
During a followup review of the licensee's actions for a higher than expected radiation dose event on March 21,1994 (Section 4.2), the inspector identified concerns regarding the
licensee's implementation of the heat stress program. No specific heat stress related events
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occurred, however, the lack of understanding of portions of the program requirements represented a potential problem.
l The program is defined by procedure No. 2000-ADM-1101.02, " Heat Stress Control l
Program." The procedure specifies work time limits (action times) based upon temperature, type of work (i.e., light, moderate, heavy), and type of clothing (e.g., work clothes, single protective clothing). For example, a worker wearing single protective clothing in a 125 F (dry bulb) environment (doing light work) is limited to a recommended action time of 15
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minutes. Personal cooling devices, such as ice vests, can be worn to increase the action time.
On March 21,1994, the equipment operator (EO) had entered the condenser and heater bay j
areas, whose dry bulb temperatures ranged between 100 F and 130 F. The Safety department previously evaluated those areas, and provided heat stress stay time guidelines for the heater bay (10 minutes at 130 F - 135 F), and other surrounding condenser bay areas (30 minutes at 100*F - 120 F). The EO had entered both the condenser and heater bay areas for approximately 30-35 minutes with no adverse heat stress effects.
During that event, however, radiation controls technicians became concerned about the EO who had entered the area alone after about 25 minutes. The tour normally lasts 15-20 minutes. The EO was subsequently located by the technician. The EO was not aware of the length of his tour and did not have a watc.
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The inspector questioned several station personnel responsible for implementing the heat stress program and found that some believed that heat stress need not be considered if the i
expected work time is less than 15 minutes, regardless of other factors (e.g. temperature, type of work / clothing). The inspector also found that the licensee's critique of the pre-job discussion stated (incorrectly) that " heat stress special requirements are not required for a 15-20 minute tour." It also noted that heat stress requirements were not discussed during the pre-job briefing.
The inspector expressed a concern to Safety Department personnel that some employees appeared to misinterpret the heat stress program. Subsequently, steps were initiated to stress to the appropriate station personnel the proper interpretation of the heat stress program requirements. The inspector will monitor the effectiveness of the licensee's actions during subsequent routine inspections.
5.2 Reactor Building Structural Deficiencies During the months of February and March 1994 the licensee made modifications to stiffen the reactor building roof bracing structure. The modifications to the roof structure were part of the Systematic Evaluation Program (SEP) upgrades to strengthen it to meet the wind loading requirements discussed in the Integrated Plant Safety Assessment Report (IPSAR),
a item No. 4.3.1. During the modifications, several structural deficiencies were identified and repaired. The modifications to stiffen the reactor building were completed on March 24, 1994. Repairs made to correct deficiencies identified during the modifications, were completed on April 11, 1994.
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During the structural modifications a total of five deviation reports (DR) were issued. The DRs identified deficiencies such as missing bolts, loose bolts, and slightly deformed portions of structural or bracing components. The licensee's evaluation of each individual deficiency concluded that the reactor building would withstand the original design specification wind loadings. On March 24,1994, the licensee determined that based on the combined effects of all identified deficiencies and the difficulty of analysis of bent / deformed structural members that the reactor building roof structure was possibly outside the original design basis. This determination was reported to the NRC at 4 p.m. on March 24, 1994, in accordance with 10 CFR 50.72.
Subsequent discussions between the licensee and the inspectors indicated that a November 15, 1990 letter from the GPU Vice President and Director Technical Functions to the NRC
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reported that the reactor building roof structure did not meet the FSAR stated 80 percent of yield stress at 125 mph wind speed. It was stated in the letter that the roof structure would meet that stress level at a 100 mph wind speed. The letter also stated that modifications would be performed to strengthen the roof structure so that it would be at 80 percent of yield stress at a wind speed of 169 mph and at yield stress at a wind speed of 190 mph. These modifications were later scheduled to be completed by April 15, 199. _ _ _
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Further discussions between the inspector and the Director, Operations and Maintenance and the Acting Licensing Mant;er indicated that GPUN was going to report to the NRC under the SEP program, that modifications committed to that addressed IPSAR, Item No. 4.3.1, in j
their November 1990 letter had been completed and that they would discuss the structural
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deficiencies identified during those modifications and their corrective actions taken to effect
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repairs.
The inspector determined that the licensee had taken appropriate actions to stiffen the reactor building roof structure to meet the committed to building yield stress at a wind speed of 190 mph and to correct identified deficiencies. Actions taken by the licensee to report completion of modifications and repairs of identified deficiencies were acceptable.
5.3 Licensee Event Report (LER) and Periodie Report Review NRC inspectors reviewed the following LER and verified appropriate reporting, timeliness, complete event description, cause identification, and complete information. In addition, the need for on site review was assessed.
Licensee Event Reoort LER 94-02 described a condition outside the design basis of the plant in which the
fuel oil level on the main fuel oil tank had dropped below the FSAR documented minimum level. This event was reviewed and documented in NRC Inspection Report 50-219/94-03. This LER is closed.
Periodic Reoorts Monthly Operating Reports for February and March,1994.
- The inspector concluded that the above licensee event and periodic reports were acceptable.
6.0 EXIT INTERVIEWS / MEETINGS (40500,71707)
6,1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the senior licensee management on April 22,1994. 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 backshift inspection; 89 of the direct inspection hours were performed during backshift perieds, which included 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> during deep backshift periods.
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17 6.2 Attendance at Management Meetings The resident inspector attended an exit meeting for an examination conducted as follows:
Dale Lead Insoector Subject Report No.
04/07/94 Burritt Reactor Operator Licensing Exam 50-219/94-08 At this meeting, the lead inspector discussed preliminary findings with senior GPUN management.
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