IR 05000324/1993030
| ML20056G780 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/12/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056G777 | List: |
| References | |
| 50-324-93-30, 50-325-93-30, NUDOCS 9309070156 | |
| Download: ML20056G780 (24) | |
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- UNITED STATES
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0.,' NUCLEAR REGULATORY COMMISSION
[ o ' REGION 81 13- , $ 101 MARIETTA STRE ET, $ f ATLANTA, GEORGlA 30323
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Report Nos.: 50-325/93-30 and 50-324/93-30 Licensee: Carolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602 Docket Nos.: 50-325 and 50-324 License Nos.: DPR-71 and OPR-62 Facility Name: Brunswick I and 2 inspection Conducted: July 3 - 31,1993
. Lead Ynspector: Y 2 7 1_,: ,. / / / , 1 6//.2/f3 R.LiPrevatte,Seniogresidept' Inspector _ Date Signed-Other Inspectors: P. M. Byron, Resident Inspector M. T. Janus, Resident Inspector G. A. Harris, Project Engineer Approved y: /h [ /br 4.5 0. Christensen, Chief Date Signed Reactor Projects Section IA Division of Reactor Projects SUMMARY Scope:
This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance observation, operational safety verification, Unit 1 outage / restart, onsite review committee, action on previous inspection findings, and review of licensee event report Results:
Unit 2 operated at 100% power for the reporting perio Unit I remained in a forced outage that began on April 21, 199 ~ In the areas inspected one non-cited violation was identified regarding inadequate surveillance testing of fire detectors in the control building emergency air filtration system, paragraph 4. A weakness involving the control of access. to radiation control areas was also identified, paragraph .
9309070156 930824 PDR ADOCK 05000324~
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REPORT DETAILS Persons Contacted Licensee Employees
- K. Ahern, Manager - Operations Support and Work Control
- R. Anderson - Vice-President, Brunswick Nuclear Project
- G. Barnes, Manager - Operations, Unit 1
- M. Bradley, Manager - Brunswick Project Assessment M. Brown - Plant Manager, Unit 1 (Acting)
- R. Godley, Supervisor - Regulatory Compliance
- J. Heffley, Manager - Maintenance, Unit 2
- G. Hicks, Manager - Training .
C. Hinnant - Director of Site Operations P. Leslie, Manager - Security W. Levis, Manager'- Regulatory Affairs (Acting)
- R. Lopriore, Manager - Maintenance, Unit 1 G. Miller,' Manager - Technical Support
- E. Northeim, Manager - Nuclear Engineering Department (Acting)
- C. Robertson, Manager - Environmental & Radiological Control J. Titrington, Manager - Operations, Unit 2
- C. Warren, Plant Manager - Unit 2 G. Warriner, Manager - Control and Administration
- E. Willett, Manager - Project Management-Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel and security force a-;;: u r * Attended the exit intervie Acronyms and initialisms used in the report are listed in the last paragrap . Maintenance Observation (62703) ,
The inspectors observed maintenance activities, interviewed personnel, and reviewed rec:,rds to verify that work was conducted in accordance with approved procedures, Technical Specifications, and applicable industry codes and standards._ 'The inspectors also verified that:
redundant components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacement parts were used; radiological controls were proper; fire
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protection was adequate; quality control hold points were adequate and observed; adequate post-maintenance testing was performed; and
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independent verification requirements were implemented. The inspectors independently verified that selected equipment was properly returned to servic Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance. The inspectors observed / reviewed portions of the following maintenance activities:
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WR/JO 93-ALQR4 DG Service Water Pipe Replacement [
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WR/JO 93-AXAU1 DG Service Water System Piping Repairs WR/JO 93-AWZXI Service Water System Piping Repairs l
WR/JO 93-AWEll Replacement of DG No. 1 Thrust Bearing
, PM 82-221-L Replacement of IB Conventional Service Water '
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PM 92-091 Replacement of Unit 1 A and C RHR SW Pumps
} PM 92-070 Unit 1 Repair / Replacement of Instrument Racks !
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The first three activities involving repairs to service water piping are discussed in detail in paragraph 5. The two DG maintenance efforts are
also discussed in paragraph 5. The inspector noted that procedures were ,
at the job site, adequate craft were assigned and they were ,
knowledgeable of the procedures and job requirements. The inspector did '
not observe any strengths or weaknesses during these activitie '
Violations and deviations were not identified.
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3. Surveillance Observation (61726) ,
The inspectors observed surveillance testing required by Technical
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Specifications. Through observation, interviews and record review, the ;
inspectors verified that: tests conformed to Technical Specification
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requirements; administrative controls were followed; personnel were
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qualified; instrumentation was calibrated; and data was accurate and .
complete. The inspectors independently verified selected test results ;
and proper return to service of equipment. The inspectors .
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2-MST-AMI27R AMI Div. I Suppression Pool Temperature Monitor Calibration '
2-SP-91-015 Power Plant Upgrade Project ;
, 2-PT-8.1.3d LPCI/RHR System Component Test Loop A ,
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0-MST-DG-500R DG No. I 18 Month Inspection !
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2-MST-R.PSIIW Main Steam Line High Radiation Channel !
Functional Test !
y 2-PT-37. Reactor Feed Pump "A" Turbine Governor Trip j .. Mechanism Test
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i The inspector noted that procedures were followed and no deficiencies were identified while observing the above test Violations and deviations were not identifie '
4. Operational Safety Verification (71707)
The inspectors verified that Unit I and Unit 2 were operated in compliance with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing records and independent verification of safety system statu The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met. Control operator, ,
shift supervisor, clearance, STA, daily and standing instructions and jumper / bypass. logs were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specification Limiting Conditions for Operations. Direct observations of control room panels, instrumentation and recorded traces important to safety were conducted to verify operability and that operating parameters were within Technical Specification limits. The inspectors observed shift turnovers to verify that system status continuity was maintained. The inspectors also verified the status of selected control room annunciator Operability of a selected Engineered Safety Feature division was verified weekly by ensuring that: each accessible valve in the flow path was in its correct position; each power supply and breaker was closed.for components that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the valve operator; there was not leakage of major components; there was proper lubrication and cooling water available; and conditions did not exist which could prevent fulfillment of the I system's functional requirements. Instrumentation essential to system l actuation or performance was verified operable by observing on-scale l indication and proper instrument valve lineup, if accessibl The inspectors verified that the licensee's HP policies and procedures were followed, except as noted in paragraph 5. This included observation of HP practices and a review of area surveys, radiation work permits, posting and instrument calibratio The inspectors verified by general observations that: the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and packages were checked prior to entry into the PA; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identification badges; personnel in vital areas were authorized; effective compensatory measures were employed when required; and security's response to threats or alarms was adequat . - . ,. . ..,, , - .- - -
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The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked clearances and verified the operability of onsite and offsite emergency power source Three-Year Plan
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The inspector reviewed the June 1993 Three-Year Plan Monthly Report and found that the licensee had completed 130 of the 154 initiative action steps and project phases that were scheduled for January I through June 30, 1993. Twenty-seven initiatives and seventy-eight projects were scheduled to be in progress at this time. All initiatives and 69 of 78 projects were being worked. Nine projects were on hold and under management review for rescheduling /reprioritization. A total of 48 activities were scheduled for completion and 50 were actually completed in June. Thirteen initiative actions were completed early and three previously late items were also completed. Twelve initiative actions and two project phases were delayed. Three were undergoing management review and eight resulted from reprioritization of resources to support Unit I restart. The following are some of the major accomplishments for June:
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completed total quality fundamental training for all site
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personnel (TY 201-9A)
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trained on ACMS, Al-58, and AMMS to improve clearances and upgrades on licensed operator training material and aids (TY 202)
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completed the study to determine facility needs (TY 206)
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completed procedures to implement new procedure control process (TY301)
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enhanced corrective action program to include management review process for root cause; implementation of standardized report format for tacking and trending; and training in self-assessment and statistical analysis (TY 303)
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developed a predictive maintenance program procedure (TY 501)
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developed optimum organizational structure and transition plan for staffing site engineering (TY 506)
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assessment of ISI/IST program (TY 507)
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completed design for replacement of Unit 1 RHR F003 A and B and F0024 A and B valves (PID G0010A)
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completed design of LPRM cable replacements (PID G0075A)
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completed design of Unit 1 CAD subsystem divisional
separation (PID G0156A)
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Project management and the Site Review Group are currently reviewing all projects. This review and evaluation is currently scheduled for completion by August 30, 1993. As a result of reviews conducted in June,10 projects were placed on hold and 21 are expected to have schedule changes. An example of the above changes was that the design and construction of the snubber repair and hot calibration / test equipment shop (TY 206-3A) scheduled to start in June was superseded by the Work Control Center and Hands On Training Facilit The licensee has approved the plan to upgrade site facilities. Approval for construction of the Work control Center and a hands-on-training facility (TY 206) demonstrates management's commitment to improve the site working conditions. The assessment of the effectiveness of the Three-Year Plan is addressed in Inspection Report 50-325/93-32 and 50-324/93-3 "
Reactor Vessel and Fuel Debris The licensee inspected the fuel removed from the Unit I reactor vessel to determine which fuel cells were leaking. The inspection identified two leaking fuel cells. The licensee planned to inspect 60 cells for damag If damaged fuel cells were detected, the sample size would be increase On July 4,1993, the licensee commenced inspection of the fuel cells and !
debris was found in over 50 percent of the examined assemblies. A l decision was then made to inspect all 436 fuel cells. Visual inspection l was performed utilizing an underwater television camera. Debris has l been found in 68 of the 116 fuel cells examined to date. The inspector i observed the inspection of several fuel cells. The debris appeared to !
consist of various sized material with the larger pieces resembling ;
machining chips. The debris was removed from the fuel cells and placed '
in a container at the bottom of the spent fuel pool. The licensee lowered a magnet into the container to determine if any of the material was magnetic. The inspector observed this evolution and noted that several metal chips adhered to the magnet. The chips had radiation J levels of two to five R/hr. One chip was sent to the Harris E&E center -
for analysis. It was determined that the chip had characteristics which resembled 304 stainless steel; however, the licensee was unable to i determine the carbon level. The licensee is attempting to locate a laboratory with hot cell facilities to obtain a confirmatory analysis and carbon content of the materia '
A remote miniature submarine was used to inspect the bottom of the reactor vessel for debris. The inspection revealed primarily soft material and a piece of lockwire. The licensee cleaned the vessel bottom, but did not determine the makeup of the debris because of the difficulty in separating the material. An inspection of the bottom core support plate revealed debris similar to that found in the fuel cell _- _ _ _ _ _ _ .
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The reactor vessel has been cleaned and the licensee plans to recommence fuel inspection about August 5. The inspector will continue to follow this effor CBEAF Failure As addressed in Inspection Report 325,324/93-27, tiie inspectors identified that the licensee had discovered that the heat detectors in the CBEAF units were wired incorrectly. This resulted in the opposite train isolating when the detectors were actuated. The detectors had been installed and incorrectly connected by Plant Modification PM 79-308 in 198 Eh'R 08739RF was written by the licensee in September 1992, to evaluate problems with CBEAF flexible conduit. The evaluation identified a procedure concern in that the functional test (PT 34.4.1.3, Control Building Instrumentation Operability) of heat detectors in Fire Zones 15 and 16 verified the common alarm function and not individual channel operability. Technical Specification 4.3.5.7.1 defines a channel bistable functional test as the injection of a simulated signal into the channel sensor to verify operability, including alarm and/or trip functions. ACR 92-723 was written to document and provide corrective actions for this concern. Revision 13 to PT 34.4.1.3 (dated February 16,1993) was implemented to correct the surveillance deficienc The heat detectors which isolate the CBEAF train were added to the CBEAF system in a 1980 modification to satisfy the requirements of BTP APCSB 9.5-1 dated January 1, 1977. The inspector reviewed the Fire Protection Safety Evaluation Report dated November 22, 1977, and noted that section 4.4.2 states that the CBEAF charcoal filters do not require automatic suppression systems since the filters are normally isolated and radioactive particles would not cause ignition. The inspector also reviewed the Control Room Habitability Safety Evaluation dated October 18, 1983, and found that no potential existed for overheating or igniting the charcoal. The Control Room Habitability Evaluation, NUS 3697, Revision 2, dated February 1983, page A-13, analyzed the acceptability of the short-term use of Self Contained Breathing Apparatus by control room personnel for smoke in the control room. This allows for manual isolation of the ventilation system. The above safety evaluation found this acceptable. The inspector concluded that this was not a safety concern since there was no potential for ignition of the charcoal and the heat detectors would never be actuate The heat detector wiring error was promptly corrected. After reviewing the modification package and associated drawings, the inspector determined that the initially used wiring schematics were correct. The conduit drawing (9527 F 3896 sheet 5) incorrectly designated Zone 16 detectors for the 2A CBEAF and Zone 15 for the 2B CBEAF. All other drawings correctly assigned Fire Zone 15 detectors to the 2A CBEAF. The design review process and post modification testing did not identify this discrepancy in 1980. The inspector considered the previously
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performed surveillance test inadequate in that the detectors were not fuily tested. The post modification test only demonstrated that the dampers clcsed and the recirculation fan shut off upon the receipt of the test signa The inadequate surveillance procedure resulted in the failure to demonstrate the operability of Fire Zones 15 and 16 as required by TS 3.3. This is a Violation: Inadequate Surveillance Tests (325,324/93-30-01). However, this violation will not be subject to enforcement because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy. The licensee identified the procedural deficiency and revised the procedure. The installation deficiency was identified the first time the revised surveillance was performed and the discrepancy immediately corrected. The licensee did not identify other similar conditions during their review. The inspector believes the licensee's corrective actions will prevent recurrence. In addition, there was minimal safety significance associated with this failure because analysis has shown that a LOCA will not generate sufficient heat to cause a fire in the CBEAF charcoal; therefore, these detectors would not be actuate Cracks in Core Support Shroud As a result of cracks previously discovered in the circumferential weld of the core support shroud in a reactor outside the United States, Rapid Information Communication Service Information Letter, (RICSIL)
No. 054, " Core Support Shroud Crack Indications," dated October 3, 1990, was issued by the reactor vendor and recommended that all BWR owners inspect the shroud welds at the next refueling. The licensee inspected the Unit 2 shroud during the 1991 refueling outage and did not identify any cracking at that time. Unit I was inspected during the current refueling outage and cracking was identified at two weld location Axial indications were identified at several locations in the heat affected zone of the circumferential weld in the shroud (H-4 weld).
Cracking was also identified in the heat affected zone of the upper guide support to core shroud weld (H-3 weld). The areas of interest were visually inspected from inside and outside the shroud. No indications were observed from outside the shroud. Inspection of the H-3 weld from insice the shroud was limited because of accessibilit The licensee assumed the H-3 crack to be 360 degrees since indications were observed at each inspection poin On July 12, 1993, a meeting was held to discuss this issue. GE stated that cracking in the H-3 weld had not been previously identified in other units. They also noted that the Unit I shroud had been subjected to less radiation than the shroud described in the RICSIL. GE was contracted to analyze the crack. An ultrasonic test (UT) was conducted to determine crack depth at selected points in the H-3 and H-4 weld The inspector observed the preplanning for the UT where decisions were made on technique, tooling, transducer angularity and location of areas to be examined for a given location. To perform the inspection, a
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transducer was mounted on the end of an 80 foot pole which was manipulated from the refueling bridge. The location of the H-3 welds inside of the shroud made transducer placement difficult. A mockup of the core plate and upper section of the shroud was constructed to qualify the procedure and fixture. The inspector observed the l qualification process and concluded that the method would work. An ,
underwater TV camera was used to locate the inspection areas and verify j that the transducer could be properly positioned. , 1 On July 15 and 16, the licensee performed the UT of the H-3 and H-4 welds. The licensee and GE both had two Level III certified NDE l inspectors viewing the CRT and directing the placement of the transducer. The licensee recorded the examination by video taping the underwater TV camera and Polaroid photographs of the UT readings on the l CRT. The inspector observed a large portion of the examination. It was noted that the operator experienced difficulty in positioning the transducer during the inspection. The video views confirmed the placement and seating of the transducer, as well as the inability to seat the transducer at some locations. The TV view revealed that actual H-3 overlay dimensions were greater than shown on the drawing. This resulted in the licensee using a narrower transducer to obtain UT dat The inspector concluded that dependable data was obtained and the operators demonstrated proficiency in transducer and equipment manipulatio The initial data indicated a maximum crack depth of approximately 0.40 inches. The readings from both sides of the shroud were consisten The licensee's contractor used a crack depth of 0.5 inches for the analysi On July 21, 1993, the licensee issued NDE Report No. R-127 which contains the results of the Unit I reactor vessel shroud UT. Data was obtained from six interior and six exterior locations for the H-3 circumferential weld and one exterior location for the H-4 weld. The H-3 crack depth ranged from 0.18 to 0.40 inchso and the H-4 crack depth was 0.250 inches. Preliminary results from the analysis indicate that the predicted H-3 crack growth at the end of the next cycle will not exceed 1.0 inches. Presently, the maximum analyzed flaw limit is 1.35 inches. The H-4 cracks are approximately one inch long and the calculated flaw limit is 50 inches. The report justified operation for one additional cycle. The report also recommended that boat samples be obtained from both weld areas for metallurgical analysis. The licensee plans to obtain these samples prior to core reloa The licensee re-examined the tapes from the Unit 2 inspection conducted in 1991 using a digitized enhancement process. The re-examination revealed three indications in the Unit 2 shroud. All were in the heat affected zone of the H-2 weld at the reactor vessel core shroud transition plate. Two were adjacent, above and below the weld, and the i third was approximately four feet away. GE has completed an analysis l which shows that these cracks will have no adverse effect for the next !
several operating cycles. The licensee issued EER 93-0477 which
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9 j concluded that the cracks do not pose a concern to normal operation of the reactor. It recommends continued Unit 2 operation and examination '
of the weld indications for new cracks or existing crack growth during the next refueling outage (scheduled for April 1994).
Plant Material Condition !
On July 7, while accompanying an auxiliary operator on turbine building rounds, the inspector noticed a small mechanical vacuum pump sitting !
adjacent to the 2A turbine building chiller on the roof of the control '
building. The vacuum pump is used to maintain a vacuum on a HVAC chiller condenser. The inspector observed that the pump was extremely hot to the touch and oil was on the ground adjacent to the pump. The inspector observed that the roof was coated with tar and expressed a concern to the auxiliary operator about this potential fire hazard. The auxiliary operator de-energized the pump and nottfied fire protection personnel and the shift supervisor. A piece of fire retardant material
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was placed under the pump as a temporary fire protection measur !
The inspector noticed that the control building HVAC duct work was l leaking water into collection buckets from three overhead ducts in the HVAC equipment room. Numerous mop heads were placed on the floor to absorb the water. The inspector also observed that a metal bar, used to I erect scaffolding for work on the HVAC system, was protruding into the normal passage area. The inspector was concerned about this tripping i hazard and pointed this out to the auxiliary operator who immediately i roped off the are The inspector noticed that the local pressure indicator 2-TCC-PI-567 for i Turbine Building Closed Cooling Water had malfunctioned and was '
unreadable. The broken indicator was not tagged with a trouble ticke This item was also identified to plant personnel for corrective actio Feedwater Flow Testina On July 15, 1993, the licensee informed the resident inspector that they had received preliminary results from the sodium trace feedwater flow test conducted on July 2. The test was performed on Unit 2 to verify feedwater flow and to detect any corrosion or fouling of the feedwater flow venturis. The test was conducted as part of the power uprate program and is tesed to verify feedwater flow and actual power level The sodium trace test was also being used to qualify a rubidium test for future use on Unit 1. With Unit 2 stable at 100% gower, General Electric conducted the test and performed the analysis of the test results. The preliminary results indicated that calculated feedwater flow corresponded to 101.08% reactor power. In response to this information, licensee management directed that actual reactor power be reduced to a value below the TS limit. Unit 2 reactor power was reduced to an indicated value of 98.5%. It will remain at this value pending further licensee evaluatio ._ _ . . __ _ _ _ _ - _ _ _ _ __ _ _ __. _ _ _ _
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Licensee personnel performed their own evaluation of the test procedure and results looking for possible sources of error which could lead to the lower flow reading seen by the instrumentation which feeds the plant process computer. They were able to verify the low indicated flow ,
reading based on calculations from a different set-of flow l instrumentation installed as part of the pever uprating tests. The inspector reviewed the above data, calculated the flow, and reached the same conclusion. This second set of instrumentation yielded feedwater J
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flow values which corresponded to those which fed into the plant process i computer. Based on the supporting evidence, the licensee determined I that some feedwater flow nozzle erosion degradatien had occurred. This j degradation has been seen at other plants where this test has been perfomed -in the pas ;
As a result of this feedwater nozzle degradation, the licensee and GE -
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are in the process of independently performing a series of calculations to determine new calibration constants and spans for the feedwater flow '
instrumentation. Once these calculations are complete, the licensee and GE will compare values and determine the proper set of values to be used. These corrected values will then be used to perform a calibration of the feedwater flow instrumentation which inputs to the plant process computer. The inspector will review these calculations and calibration procedure when they become availabl ,
One non-cited violation involving an inadequate surveillance test was identifle ' Unit 1 Outage / Restart (NOTE: Asterisked items are restart issues from CP&L's letter dated ;
July 23,1992.) . ,
- (00en1 CP&L Item D4 Reduction in Corrective Maintenance Backloa The inspector started tracking this item on Unit I after the restart of f Unit 2 in May 1993. The licensee developed and published their restart goals on May 24, 1993. At that time there were approximately 4,000 items in the overall backlog for Unit 1 that were planned for completion '
prior to restart. The scheduled restart date was established as 4 September 23, 1993. The goal and tracking categories established by the .
licensee, with current status, are as follows:.
Indicator Goal Status 5-Focus Systems <650 511 ;
(onlineWR/J0s) :
Focus Systems <80 357 ;
(Priority 1-4 WR/J0s) 1 Other Systems <80 191
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11 1 Indicator Goal Status (cont'd)
Control Room Annunciators / <5 45 Instruments Operator Work Arounds <25 99 !
Permanent Caution Tags 0 0 STSI Items <26 528 !
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Temporary Modifications <20 25 The above goals are similar to those used for Unit 2 restart with )
slightly less open items planned to exist at restart. The number of ;
open items on Unit I has increased significantly since the unit was 1 shutdown in April 199 In 1992 and early 1993 the licensee focused their resources on returning Unit 2 to op /ation. Following the Unit 2 l restart in April 1993, the emphasis focused on Unit 1. After Hay, the backlog of work increased as the licensee worked to develop and input all required work items into the schedule. Difficulty was also experienced in the areas of planning and effective work management. By mid-June, the licensee had established a better schedule which incorporated all planned WR/J0s. Since that time progress has been made. The licensee has reached a level where they have accomplished approximately 46 WR/J0s per day for the last two weeks; however, there were also approximately 8 WR/J0s per day added during this same tim These items generally resulted from a required increase in work scope identified during maintenance activities and emergent support tickets !
that had not been incorporated into the initial job planning. The .
inspector will continue to track and follow progress on this item until l Unit I restar *fClosed) CP&L Item D5 Reduction of Preventive Maintenance Backloa The licensee has scheduled to have the preventive maintenance backlog completed by restart of Unit 1. When this schedule was developed there was a backlog of 235 items for Q-list components and 273 items for non Q-list components in addition to those that were being routinely scheduled. As of July 28, they have completed all"except 40 Q-list and 101 non Q-list items. It appears that the licensee has control of this item and should not have difficulty in completing the remaining items prior to Unit I restart. The inspector will continue to follow this item to task completio For reporting purposes this item is close Unit 2 Backloc/ Goal Unit 2 restarted in April with a backlog at or near the published goal The licensee (in meetings with the NRC) stated that after Unit 2 restart and completion of power ascension, efforts would be applied for
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continued reduction of the backlogs with a goal to achieve "Jorld Class" performance by 1995. Since Unit 2 restart, the licensee has added emphasis and resources to reduce the backlog in Unit I to an acceptable level prior to restart of that unit in September 1993. Considerable progress has been made on Unit 1; however, on Unit 2 this effort is considered only marginal. The backlog of corrective maintenance items (type 10) has increased from 1353 to 2056. Fourteen hundred and seventy two of these items can be worked on-line. During the time this backlog was increasing, the licensee reduced the maximum maintenance work hours j to less than 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> per week, reduced contractor assistance for Unit 2 '
maintenance by 34 persons, and Technical Support overtime has been ,
reduced to near zero except for emergent items. On July 9, the licensee i published the work plan and schedule for backlog reduction described in ;
the BNP three-year plan initiatives, TY 103, Corrective Maintenance '
Backlog, and TY 304, Backlog Reduction. These initiatives established i the following goals for the maintenance backlog: l
Item Current 1993 Goal 1995 Goal l Unit 1 Unit 2 Running rate N/A 169 days 60 days 45 days I Average age N/A 225 days 120 days 90 days Total N/A 1472 <600 within <600 within 2 cycles 2 cycles Focus system 503 338 100 100 (Priority 1-4)
As can be seen from the above numbers, the licensee has not met these '
goal The inspector discussed this concern with the Unit 2 Plant Manager and the Site Vice President. They agreed that the corrective maintenance backlog had increased during startup and power ascension testing, but had recently flattened out and shown a slight decline. The Site Vice !
President stated that he has contracted for 24 additional maintenance personnel to reduce the corrective maintenance backlog. These resources are planned to be added by August 16. The Site Vice President also stated that 39 additional permanent maintenance personnel (10 I&C,19 planners, 10 mechanical) have been authorized. These personnel will be placed in a training status until they are qualified. In the interim, the above mentioned 24 contracted personnel will be used to work on backlog reduction. Site management has stated their goal is to reduce Unit 2 type 10 and 20 corrective maintenance backlog items to less than 1200 by the end of 1993. The inspector concluded that site management is aware of the need to increase emphasis and add resources to reduce the Unit 2 maintenance backlog. This item will continue to be fcllowed and reported on as warrante .
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Preventive Maintenance on Diesel Generator No. 1 On July 13, 1993, DG No. I was taken out of service for the performance of OMST-DG500R, Emergency Diesel Generator 18 Month Inspection. This inspection is performed to identify potential problems and to ensure that the DGs are functioning properly. The inspection implements the surveillance requirements of TS 4.0.5 and 4.8.1.1.2.d.1. In acco, dance l with TS, the licensee has 7 days to complete the MST and is required to i demonstrate the operability of the other DGs within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and at l least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The first operability test on DG No. 2 was 4 invalid due to lack of proper preparation for the test. Periodic Test !
procedure 0-PT 12.8, Diesel Generator Operability Test, requires that a l calibrated Simpson volt-ohm meter be used to verify that the starting contacts changed state when diesel speed reached 514 RPM. The test ,
acceptance criteria requires that the diesel obtain this speed in less i than 10 seconds. Due to a ch mge in the Measuring and Test Equipment
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Calibration Program, a calibrated Simpson volt-ohm meter was not available for use during this test. This change had not been reflected j in the diesel operability procedure. The procedure specified that a digital volt meter (DVM) could be used as an equivalent substitute; however, the slow response time of the DVM resulted in a failed test, with an indicated start time of 10.02 seconds. Based on the test results, DG No. 2 was declared inoperable. Additionally, the strip !
chart recorder used as a backup measure of start time failed to give the !
proper response time for the DG start, because it was set on slow speed instead of fast spee With two DGs inoperable, TS 3.8.1.1 requires that the remaining AC power sources be demonstrated operable within two hours and at least three DGs .
be restored to operability within two hours or place the units in hot ;
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shutdown within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within the
, following 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG Nos. 2 and 3 were successfully tested and the test run for DG No. 4 was started within the two hour time frame; however, the test run on DG No. 4 was not successfully completed until 10 minutes after the TS required two hour time frame had expired. This caused the licensee to enter TS 3.0.3. The licensee exited TS 3.0.3 when the diesel test was
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complete The inspector noted that proper pre-job preparation should have been performed to avoid unnecessary delays in the testing of this safety-related equipmen .
The preventive maintenance portion of the OMST requires a visual inspection for indications of wear and degradation on the main bearings and thrust bearings. A failure of the thrust bearings on this DG had previously occurred in October 1992. The visual inspection indicated some discoloration of the installed thrust bearings. The thrust bearings and the number 9 main bearing were removed for closer inspection. The number 9 bearing showed no signs of wear, however, the thrust bearings showed signs of heat stress, radial cracking, and
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14 I plastic metal deformation. The licensee conducted a thorough
investigation of the thrust bearing. They concluded that frictional contact induced by shaft wobble caused the excessive heat and subsequent damage to the thrust bearing. It was determined that a thinner thrust bearing with more clearance should be installed. Three thin (0.461 inches) and one thick (0.466 inches) thrust bearings had originally been installed in the engine. According to procurement documentation, the licensee changed to the thicker bearings because they had been informed by the vendor that the thinner bearings were obsolete. The inspector reviewed the procurement documentation and was unable to find any engineering design justification for the change to.the thicker thrust i bearings. The licensee's proposed corrective action, changing to i thinner thrust bearings, created clearances that were larger than those l specified by the technical manual. The inspector discussed this concern '
with the licensee and found that the licensee had discussed the issue with the original designers of the engine and with a consultant hired to i help investigate the thrust bearing problem. Both agreed that the l
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increased clearance was acceptabl The consultant concluded that the thrust bearing problem was a recurrence of the same problem that occurred in the fall of 1992. In addition, he stated that the root cause of the problem was not related to a single factor, but a combination of factors including thrust clearance, crankshaft wobble, thrust collar alignment, and thrust l
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bearing thermal expansion, The observed cracks were the result of a i combination of radially non-uniform frictional heating and compressive residual stress. The consultant stated that the cracks did not constitute a threat to the availability or reliability of the engin The consultant recommended that DG Nos. 2, 3, and 4 be inspected when available, since the thrust bearing problem had been determined not to ,
affect the reliability of the engine The inspector reviewed the oil analysis data and found no evidence of metal wear. The licensee explained that this was due to the relatively small amount of wear particles in the large volume of oil. A teleconference was held on July 15, 1993, between NRR, Region II, and the licensee, to discuss thrust bearing degradation, clearance concerns, and post maintenance diesel test run The licensee purchased the available 0.466 inch thrust bearings and had them machined to 0.416 inches. The licensee and the inspector examined the newly installed thrust bearings after several unloaded and loaded maintenance test runs and found no evidence of the heat stress, wear, or degradation that had previously occurred. The licensee plans to inspect the thrust bearings on the other diesel generators during their next regularly scheduled maintenanc Some additional problems were identified with DG No. I and its auxiliary systems during the post maintenance runs. These included a relief valve on the air receiver which lifted approximately 20 psi below setpoint, loss of nearly one and one-half barrels of lube oil due to the failure
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of a Dresser coupling, and a leaking manual fuel oil valve that had to be reworked. These problems resulted in DG No. I remaining inoperable for an additional 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> During the first loaded maintenance run, an auxiliary operator noticed that diesel motor jacket water and lube oil temperatures were increasing beyond the normal operating range. Subsequent investigation by the shift supervisor re.ealed that the jacket water temperature control valve had been installed backwards. The shift supervisor halted the maintenance runs. The valve was removed and reinstalled in the correct orientation. Using P& ids and a technical manual, the inspector verified the orientation of the valve on all the diesel generator engines was correct. The inspector reviewed the post maintenance test for the valve which required maintenance crews to examine the valve for leakage and proper operation. The post maintenance test did not instruct the crew to check for proper valve body _ orientation. Proper valve body orientation ensures that the temperature control valve will function properl On December 27, 1992, a trouble ticket had been written which stated that the thermostatic position indicator had been installed in the wrong location on the valve. Subsequent investigation by the inspector revealed that the valve's internals had been previously installed in the reverse orientation as indicated by position indicators for the thermostatic control assembly. The inspector questioned whether the valve had been inoperable while in this configuration. The inspector observed the licensee disassembling the valve and noted that the internals were symmetric in configuration, and concluded that the operating characteristics of the valve were not adversely affecte These conclusions were confirmed by the valve manufacture Nuclear Service Water System Leak During the current Unit I outage, the licensee initiated work on PM 91-070 to install a new section of 12-inch piping from the Unit I nuclear service water (NSW) header to the lower elevation of the diesel generator building. When completed in 1995, this modification will rsplace the existing Unit 1 18-inch carbon steel, cement lined piping with copper nickel piping that is less susceptible to salt water corrosion. The Unit 1 NSW system outage started on July 1 TS 3.7.1.2(b)(2) requires that the NSW system be returned to an operable status within 14 days or declare all four diesel generators inoperable and take action as required by TS 3.8.1.2 for Unit I and 3.8.1.1 for Unit 2. If the licensee were unable to complete the work in the allotted time, this would result in entry into TS 3.0.3 for Unit TS 3.0.3 requires the unit to be in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown within the following 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> The licensee completed the work associated with the replacement pipe on July 25. After refilling and venting this system, a hydrostatic test at 110% (165 psig) design pressure was started during the day of July 2 The test personnel were unable to provide adequate pressure with one
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hydrostatic pump so a second pump was connected to provide additional water volume. The pumps were able to achieve, but not able to maintain the hydrostatic pressure. Subsequently, water was found bubbling out of the ground on the east side of the A0G building. The licensee determined that a leak existed and began an investigation to locate the source. Based on the established hydrostatic boundary, they concluded l that the leak had to be in the 30-inch NSW header to the reactor building or the 18-inch branch line to the DG building. These portions t of the system were drained and personnel crawled the 30-inch main header l and conducted a visual inspection. No leaks were found in this line so it was determined that the leak was between the Unit 1 DG cooling water l
isolation valve, ISW-V255, and the point where this line was connected
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to the NSW main header. A review of the yard piping composite plan determined that the piping connected to the NSW header under the north side of the A0G building at a depth of approximately 12 feet and ran underground in a southwest direction to ISW-V25 Excavation was started on Monday, July 26, with plans to cut, cap, and bypass the defective section of piping. While work was progressing in this excavation, a mobile miniature camera was used to inspect the 18-i inch piping. A small hole was found approximately 42 feet from the 30/18-inch pipe branch connection. Corrosion and piping interferences prevented the camera from inspecting the entire section of pipe. Based on the above, the licensee decided to cut the 18-inch DG SW line at the
- 30/18 header junction and at a point approximately 25 feet from the
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ISW-V255 valve. The defective section of piping was abandoned and a code class repair jumper was placed to tie the new 12-inch DG building service water line to the existing 18-inch SW cooling line. These repairs were completed on July 29, at 1:00 The system was hydrostatically tested on July 29, at 9:00 p.m. The excavation area was backfilled and the Unit 1 NSW system was declared operable on July 3 The inspector inspected and observed the following activities associated with the above:
- Excavation and shoring l e Camera inspection of the leaking 18-inch piping e Welding and NDE activities on replacement piping e Hydrostatic testing e Backfill and compaction of excavated areas In addition to the above, the inspt.ctor reviewed WR/J0s 93-AXAU1 and 93-AWZXI used to perform the emergency repairs while a design package was being develope At the start of the backfill, the inspector questioned the licensee as to what methods would be used to ensure adequate soil compaction. They stated that the services of a contractor had been obtained for this task. A NRC regional inspector with expertise in this area was on-site, and his assistance was required to evaluate this area. A review of the contractor's creder.tials on July 30 revealed that he was not on the list of Qualified Vendors, and had not been approved by the licensee to work on "Q" class jobs. At that time, the licensee stated that the backfill l
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was not a "Q" class activity. After lengthy discussions the licensee agreed that the activity was "Q" class and obtained the services of a Qualified Contractor to perform verification testing of the soil and backfill compaction. Further details on this item are contained in the regional inspector's report 325,324/93-3 The licensee evaluated the above concern with the backfill in EER 93-0500 and determined that the backfilled soil was interim acceptable based on Seismic Analysis SA-SW-B943-91070. The analysis and initial results of the validation of in-situ soil densities by a qualified contractor were reviewed by the regional inspector and determined to be acceptable. After resolution of the above, the Unit I service water system was returned to an operable status on July 30, at 4:00 The licensee demonstrated effective management and teamwork in organizing its resources to complete the above emergent activity and preclude Unit 2 shutdown. A sense of urgency, cooperation, ownership !
and support for this effort was evident throughout the site. All site l personnel were aware of the problem and believed that it could and would
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be fixed within the allotted time. The cverall effort with the exception of the soil testing was considered to be excellen Access to Radiation Controlled Areas I
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The work activities associated with the service water piping replacement i discussed above involved work adjacent to the Unit 1 Condensate Storage l Tank. The area directly adjacent to the tank has radiation levels of 5 i mr/hr or greater up to a distance of about 10 feet from the tank. This l area is normally roped off and posted " Radiation Area, RWP and Dosimetry l Required for Entry". '
The service water piping replacement activity included trenching and replacing pipe slightly inside the Southwest side of this boundary. As a result of these activities, the licensee decided to extend the RCA boundary out to a distance of 25 to 50 feet in order to permit more efficient area control. Under the above conditions, the east wall of the DG building was used as the west boundary for this area. On July 29, the inspector noticed that the barrier rope had been moved about 6 to 8 feet from the DG building and personnel were using this area as a passage to observe work activities. The inspector identified one manager inside this area without dosimetry. The inspector reviewed this with HP personnel who then reinstalled the barrier and placed a ,
roving watch in the area. The inspector and HP took readings of the l radiation levels in the area and found they were approximately 4 mr/hr ;
at 10 feet from the tank and about I mr/hr at tha location where the '
manager without dosimetry had been observed. The inspector concluded that the manager could not have received any appreciable amount of exposure. The inspector concluded that the above incident was the result of someone inappropriately moving a barrier rope, HP personnel not maintaining strict control over the area, and inattention by the manager in not observing that the radiation control area boundary was not appropriately established. This item is identified as a weaknes .
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The inspector noted that it was immediately corrected by the licensee and that ro potential for contamination existed in the area under question. Additionally, the majority of the radiation area is enclosed by a wooden fence to prevent entry. The inspector had observed numerous
- people inside this RCA boundary over a period of five days and this was
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... only incident where a person did not have the required dosimetr Torus Inspection l
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The licensee plans to recoat the Unit I torus liner during the next two i 4 refueling outages (RFOs). An inspection was performed during the l current refueling outage to define the scope of work required to recoat and repair corrosion damage. They selected four bays to be inspecte The ECCS suction strainers were also inspected. The licensee had not i planned to.desludge the~ torus or filter the water,' but believed that they could examine areas for corrosion using a device which would enable !
them to clear a small area for inspection. The divers' initial entry to ;
inspect the ECCS filters discovered that visibility was severely l'
restricted.. The inspector viewed the inspection video tapes and observed that the intake screens were barely visible. The licensee :
concluded that the ECCS strainers were intact and not clogged, but they would have to filter the torus water to improve clarity and desludge the four bays to pemit a liner inspectio :
On July 23,'the inspector toured the torus and observed the visual !
inspection of the torus liner. The inspector observed several pieces of debris floating in the water and brought it to the licensee's attention. The inspector observed the recovery of a yellow plastic glov '
On July 24, the licensee performed a UT examination of the torus to i
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determine liner thickness. The liner thickness is a nominal 3/8 inche !
The inspector reviewed the UT-results which demonstrated the liner ;
thickness to be approximately 0.40 inches. The licensee also measured l l pit depth in the four bays to determine the effects of corrosion. The i
- inspector determined that measured minimum wall thickness was approximately 0.30 inches. Procedure 1-SP-93-053, " Unit 1 Torus Liner Inspection," section 6.2, states that minimum acceptable wall thickness is 0.25 inche ,
j The inspector reviewed 1-SP-93-053 and found the procedure and results i adequate. The inspector verified through observation that the licensee ,
perfomed the inspection in accordance with the procedure. The licensee I concluded from the data that no repairs were required during the current l RFO.-
j Core Soray Soarcer Crackino On June 24, 1993, the licensee identified a four inch through-wall crack
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in the core spray B line above the shroud. On June 29, a three inch :
through-wall crack in the core spray B sparger below the shroud was also I identified. This was described in detail in Inspection Report
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325,324/93-27. GE issued their analysis of the core spray cracks in Report GE-NE-523-142-1092, Revision 0 and concluded that Unit I could operate safely without any restrictions or limitations for the next operating cycle. The licensee issued EER 93-0479, on July 23, 1993, which provides justification to use the spargers in the as-found condition. The inspector observed the photographs of the cracks and discussed the observations with the ISI and NDE personnel. The inspector also reviewed EER 93-0479 and found it to be acceptabl . Onsite Review Committee (40500)
The inspectors attended selected Plant Nuclear Safety Committee meetings conducted during the period. The inspectors verified that the meetings were conducted in accordance with Technical Specification requirements regarding quorum membership, review process, frequency and personnel qualifications. Meeting minutes were reviewed to confirm that decisions and recommendations were reflected in the minutes and followup of corrective actions was complete There were no concerns identified relative to the PNSC meetings attended. The resolution of safety issues presented during these meetings was considered to be acceptabl . Action on Previous Inspection Findings (92701) (92702)
(Closed) URI 325,324/93-27-03, Inadequate Surveillance Procedure and Post Modification Testing. This item is discussed.in detail in paragraph 4 of this report and was identified as non-cited Violation 325,324/93-30-0 (Closed) Violation 325,324/92-19-01, Licensee Failed to Conduct Engineering Evaluation Report. On January 24, 1992, a pinhole through-wall leak was identified on line 1-SW-233-3/Y-17A. This line supplies lubricating water to the pump bearings. To support an expeditious temporary repair effort, the leak was repaired with a soft rubber patch. Permanent repairs were deferred and, with no tracking LC0 initiated to serve as a triggering mechanism to complete the repairs, the patch remained in place for more than five months. EER 92-0199 was written to provide justification for the temporary repair and to demonstrate the operability of the line. The inspector reviewed the EER and found no discrepancies. The licensee revised 01-04, LC0 Evaluation and Follow-Up, to require the initiation of a tracking LC0 for pressure boundary leakage from a Class 1, 2, or 3 component. The inspector verified that the revision has been incorporated into the procedur The permanent repair was completed under WR/JO 92ABSK (Closed) Violation 325,324/92-21-02, Written Procedures Not followed:
Main Steam Line Isolation Valve Testing, Control Board Walkdown and Weekly Tag Out Audits Not Performed. This occurred when an LLRT clearance was placed on a valve to maintain it in the open position. A loss of power resulted in this valve failing to the closed positio The valve stayed in this position for approximately 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> until it
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was found during a control board walkdown by an NRC inspector. During this time period, R0's had walked down the board periodically, two shift i
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turnovers occurred each day, and a weekly control room tag audit was completed. The licensee determined the root cause of the above problem to be the result of lack of attention to detail by operators and using !
clearances for personnel and equipment protection to control test activities. The licensee's corrective action for this item was to provide training to operations personnel during the quarterly training cycle, revision of the affected test procedures to ensure that equipment !
clearances remove automatic motive power that could result in changes in l the state or position of the component, and assigning the opposite unit R0 to perform the weekly clearance audits. The licensee has additional plans to evaluate and upgrade the clearance process under the Three-Year i Plan, item TY 305. The inspector verified that the above corrective !
actions had been completed. In addition to the above, and in response '
to other violations and concerns, the licensee has rainstituted non-technical specification logs which require added monitoring of the i'
control board by operators to increase attention paid to the control board. During the recent startup of Unit 2, some instances of inattention to detail were identified which resulted in this and other actions. After the above events, it appears that operator performance in this area has improved and is receiving a higher level of management and supervisory attention. Based on the above, this item is close (Closed) Violation 325,324/92-35-01, Failure to Follow Procedures With Regard ~ to Unnecessary Reactor Vessel Drain Down. This item resulted when the control operator (CO) allowed himself to be distracted while draining the reactor vessel. The senior control operator (SCO) was also not aware that the evolution was in progress. The licensee's corrective actions reinforced the communication between the SCO and CO, as well as provided specific guidance on critical parameters that require stricter attention and second person verification. Procedures were revised to incorporate the above actions. The major change that occurred as a result of this event was to remove a large number of administrative tasks from the SCO and place them in a work control center that is i outside the control room. This has significantly reduced control room '
distractions and permits the SCO and control room personnel to focus on plant operations. The inspector verified that the" actions specified in l the licensee's response have been completed and they appear to be having a positive effect on operation (Closed) Violation 325,324/92-28-03, Failure to Control Distribution of Controlled Drawings in the Control Room. NED formerly sent advanced copies of modification drawings to the Control Room for use by the operators. The controlled drawings were removed upon receipt of the advance copy and prior to receiving instructions from Document Contro The licensee abolished the practice of advance drawings and the issuance of all site documents is now through Document Control. The inspector has verified that this practice has been implemented and no other similar discrepancies have been identified. This item is considered close .
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21 Review of Licensee Event Reports (92700) l (Closed) LER 1-91-018, Reactor Scram Resulting from Common Instrument '
Header Pressure Perturbation. Unit I scrammed when a reactor water level transmitter manifold isolation valve (1-B21-1T-N026B-4) was opened. The licensee concluded that the isolation valve was leaking and allowed a pressure transient on the common instrument header. The licensee initiated the following corrective actions which the inspector reviewed:
e Isolation valve N0268-4, its manifold, and both transmitter drain i valves were replaced and teste i
-* Surveillance Procedures 1/2 MST-RSDP21Q, RSDP and RTGB Panel Reactor Water Level Indication Channel Calibration, were revised to provide closure of root valves to ensure better isolation. The .
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inspector. reviewed 1 MST-RSDP21Q, Revision 17, and verified that the changes had been incorporate ,
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e Prior to testing,- a review was conducted of other level calibration procedures performed at power to identify those requiring root valve closure. The inspector verified that the licensee had conducted the review and that procedure change requests had been submitted as neede ;
e The licensee eva".uated the effects of leaving the common instrument rack Jrain/ calibration headers vented and the permanent removal of the hea@rs in EER 91-0423, which concluded that the tubing (headers) could be permanently removed. The inspector i reviewed EER 92-0423, Revisions 0 and 1, and found them to be adequat * The event was reviewed with the appropriate I&C personnel between July 18 and August 15, 1991. The inspector reviewed the training records of the I&C personnel who attended the briefing and verified that training was conducted, i e The licensee pressure tested manifold valves 2-B21-LT-N026B-3, -4, and -5 on November 4, 1991, using WR/JG 91-APBA1. There were no leaks or other problems identified with the valves. The inspector reviewed WR/JO 91-APBAl and concluded that the test was adequat The licensee also found that the Main Steam Line Drain Inboard Isolation Valve 1-B21-F016 actuator motor breaker tripped on i overload when the valve was being opened to equalize pressure around the MSIVs. Disassembly of the valve revealed that the l valve discs had jammed at about 75% open while opening. EER 91-0267 was written to evaluate the finding, determine root cause, and propose corrective actions. The root cause determined that the sharp edges on the valve discs were the cause and appropriate repairs were completed.
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. e The existing disc / guide design of the 3-inch double disc gate i valves was reviewed with Anchor Darling. The vendor determined
- that the failure of the affected valve (F016) to open was due to a l 1 design problem. The design allowed the use of knife edged discs ,
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in a valve body casting that allowed the top edge of the disc pack :
to open. . Under certain conditions, this combination allowed the
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< knife edged discs to spread apart at the top and dig into the
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valve body. as the disc pack cleared the seal. The vendor's fix r 7 was to provide rounded edges on the discs and modify the valve '
casting to prevent the disc pack from moving into the valve body.
E e The licensee disassembled the four Unit 2 three-inch Anchor
'. Darling double disc gate valves and increased the outside disc
!- radius from 1/64" to 1/32" as recommended by the vendor. The :
l inspector reviewed.the following WR/J0s for the reworked valves: '
E WR/JO Valve i
91-APHF1 2-B21-F016 i 91-APHG B21-F019
-91-APHH1 2-E51-F007
. 91-APHIl 2-E51-F008 ,
i The inspector verified that the discs of all four valves had been
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reworked with vendor _ representative assistance.
j e. The Unit l' three-inch Anchor Darling double disc gate valves were
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inspected and repaired under the following WR/J0s:
i E/E Valve
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91-ANLF1 1-B21-F016 i
91-ANLII' l-B21-F019 91-ANLJ1 1-E51-F007
, 91-ANLK1 1-E51-F008
- The inspector reviewed the WR/J0s and verified that- the licensee
reworked the discs and performed other work as require The' inspector's review of the above documents verified that the proposed
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LER corrective actions have been implemented.
] 9i Exit Interview (30703)
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.The inspection scope and findings were summarized on August 2, 1993,
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Lwith those persons indicated in paragraph 1. The inspectors described the areas inspected and discussed in detail the inspection findings listed below and in the summary. - Dissenting comments were not received
- from the licensee. Proprietary information is not contained in this report.
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j Item Number Description / Reference Paracraoh-325,324/93-30-01 Non-Cited Violation: Inadequate Surveillance Tests :
2 For CBEAF System Fire Detectors, paragraph ,
1 Acronyms and Initialisms - -
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ACMS Automated Clearance Management System ACR' Adverse Condition Report AMMS Automated Maintenance Management System
- A0 Auxiliary Operator A0G Augmented Off Gas BTP Branch Technical Position BWR~ Boiling Water Reactor
. CAD- Containment Atmospheric Dilution- '
CAL Confirmatory Action Letter
- CBEAF Control Building Emergency Air Filters ,
CO Control Operator DG Diesel ~ Generator
- DVM Digital Volt Meter
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ECCS Emergency Core Cooling System !
E&E Energy and Environment ,
E&RC Environmental & Radiation Control )
EER Engineering Evaluation Report I
. EWR Engineering Work Request i
GE General Electric Company Health Physics
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HP l HVAC Heating Ventilation and Air Conditioning ;
I&C Instrumentation and Control l IFI Inspector Followup Item l
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ISI Inservice Inspection IST Inservice Testing '
LCO Limiting Conditions for Operation
.LER Licensee Event Report
=LLRT Local Leak Rate Test i LOCA Loss of Coolant Accident i LPCI Low Pressure Coolant Injection LPRM Local Power Range Monitor MSIV Main Steam Isolation Valve MST . Maintenance Surveillance Test NAD Nuclear Assessment Department NDE Non-Destructive Examination i NED Nuclear Engineering Department
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NRC Nuclear Regulatory Commission l NRR Nuclear Reactor Regulation
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NSW Nuclear Service Water OMST Operations and Maintenance Special Test P&ID Piping & Instrumentation Data PA Protected Area '
PM Plant Modification *
PNSC' Plant Nuclear Safety Committee PSI Pounds Per Square Inch
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PT Periodic Test l RCA Radiological Controls Area L RF0 Refueling Outage RICSIL Rapid'Information Communication Service Information Letter
.RHR Residual Heat Removal R0 Reactor Operator RPM Revolutions Per Minute RSDP Remote Shutdown Panel RTGB Reactor Turbine Gauge Board RWP Radiation Work Permit SCO Senior Control Operator STA Shift Technical Advisor STSI Short Term Structural Integrity -
SW Service Water l TAC Technical and Administrative Center i TS Technical Specification l- UT Ultrasonic Testing .
l WR/JO Work Request / Job Order
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