IR 05000280/1996001
| ML18153A534 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/11/1996 |
| From: | Belisle G, Ganes L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A532 | List: |
| References | |
| 50-280-96-01, 50-280-96-1, 50-281-96-01, 50-281-96-1, NUDOCS 9603250191 | |
| Download: ML18153A534 (25) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report Nos.:
50-280/96-01 and 50-281/96-01 Licensee: Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:
50-280 and 50-281 License Nos.:
DPR-32 and DPR-37 Facility Name:
Surry I and 2 Inspection Conducted: January 7 through February 10, 1996 Inspectors:
- ~, Senior Resident Inspector D. M. Kern, Resident Inspector W. K~ Poertner, Resident Inspector
.1-/1-f'G Date Signed R. C. Chou, Regional Inspector, Paragraphs 3.1, 3.2, 3. W. M. Sartor, Regional Inspector, Paragraph Approved by:
G~ e Tse, e* '
Reactor Projects Branch 5 Division of Reactor Projects SUMMARY Scope:
_g_/11 { f 0 Da'te S 1 gned This routine resident inspection was conducted on site in the areas of plant operations including plant status, loss of missile protection for the IA ESW pump, operations of the turbine load limiter and self assessment; maintenance including preventive maintenance on valve I-CH-MOV-1269B, Unit I A CCHx cleaning and modification, Unit I incore D flux detector assembly troubleshooting, Unit 1 TDAFW pump governor stem movement check, Unit I turbine inlet valve freedom test, planned Unit I TDAFW pump and valve repacking, Unit 1 isophase bus duct grounding strap temperature monitoring and open item review; engineering including incorrect feedwater flow instrument span used in FFR based FLOWCALC program, crossunder safety valve I-MS-SV-109B temporary modification and open item followup review; and plant support 9603250191 960311 PDR ADOCK 05000280 G
PDR ENCLOSURE 2
including emergency preparedness program review, and plant tour observation Inspection was also conducted of FSAR commitment Results:
Plant Operations The IA emergency service water pump was declared inoperable on January 17 due to loss of missile protection. Compensatory actions were adequate to address the immediate operability concern (paragraph 2.2).
An isolated example of not updating operating procedures during the core uprate design change was noted (paragraph 2.3).
Root Cause Evaluation 95-2912, Elevated Steam Generator Sodium and Chloride Levels, was thorough and implementation of the recommendations should prevent recurrence (paragraph 2.4).
Maintenance Valve l-CH-MOV-12698 was in good mechanical condition and maintenance was accomplished in a satisfactory manne Replacement of a broken wire was performed adequately (paragraph 3.1).
The procedures used for component cooling heat exchanger modification provided adequate detail for the craft to perform maintenance, inspection, modification, and coatin An isolated weakness was noted, in that, the work package did not provide instruction to disassemble a vacuum priming valve flang Maintenance personnel were knowledgeable and skillful in doing the work (paragraph 3.2).
Ongoing repair efforts for the Unit 1 D incore detector 5 path assembly box were appropriate. Technicians were knowledgeable and the troubleshooting plan was well thought out. Actions to improve radiation protection practices within containment and stay time assessment were effectively implemented for this work activity {paragraph 3.3).
Preventive maintenance was properly implemented and evaluated to monitor Turbine Driven Auxiliary Feedwater (TDAFW) pump governor stem freedom (paragraph 3.4).
Unit 1 turbine inlet valve freedom testing was satisfactorily completed consistent with the Surry Final Safety Analysis Repor Several crossunder safety valves between the moisture separator reheater and low pressure turbines lifted and failed to reseat during the test. Appropriate actions were taken to reseat the valves and to evaluate continued operation with two safety*valves gagged (paragraph 3.5).
Planned maintenance to repack the Unit 1 TDAFW pump and steam supply valves was not effectively coordinated. Mechanics properly questioned an unexpected packing configuration, but the resolution was incorrect. The pump was incorrectly repacked and tested twice, before the error was identified and
corrected. Failure to correctly resolve the work instruction conflicts for repacking the TDAFW pump was identified as a non-cited violation. Planning and work coordination weaknesses extended TDAFW pump unavailability one day beyond the planned maintenance windo Post maintenance operability testing was well controlled in accordance with procedures (paragraph 3.6).
The licensee's close temperature monitoring of the Unit 1 isophase bus duct grounding straps was appropriate (paragraph 3.7).
Corrective actions to address a 1993 reactor coolant system leak during a resin transfer evolution were generally well implemente Licensing engineers reopened one action item which the inspectors determined had been prematurely closed (paragraph 3.8.1).
The licensee correctly determined that the anchor bolt interaction ratio for pipe support No. H-34 was acceptable using current design criteria (paragraph 3.8.2).
Engineering The Unit 2 feedwater flow based FLOWCALC program had not been updated to incorporate installed feedwater flow instrument spans since February 199 Corrective action to a 1994 overpower event on Unit 1, failed to identify this pre-existing discrepanc Failure to properly implement actions to identify and correct the existing Unit 2 secondary calorimetric program error is a violation (paragraph 4.1).
A safety evaluation was properly performed to justified a temporary modification to gag the 1-MS-SV-1098 crossunder safety valve (paragraph 4.2).
The corrective action plan to address a 1994 reactor overpower event was detailed and thoroughly addressed the causal factor Proceduralized alternate power indication verification during power ascension was a positive initiative. Process improvements for setpoint and scaling design changes were effectively implemented to preclude recurrence in the future (paragraph 4.3.1).
Plant Support The licensee's emergency response capability was maintained at a fully proficient level of operational readines Program strengths included hardware enhancements to improve the reliability of the emergency sirens located in the IO-mile emergency planning zone, the availability of a full time emergency planning trainer, and a recent initiative to evaluate the effectiveness of the overall program through an emergency response organization member survey (paragraph 5.1).
Fire protection and safety engineers initiated action to clarify station policy regarding leaving fire barrier doors open on the blow-off chain closure device. This policy appropriately reinforced the intention to rely on passive safety devices versus active safety devices when practical (paragraph 5.2}.
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REPORT DETAILS Acronyms used in this report are defined in paragraph.0 PERSONS CONTACTED Licensee Employees
- Ashley, J., Administrative Services
- Benthall, W., Supervisor, Procedures
- Biron, M., Station Nuclear Oversight Blake, H., Jr., Superintendent of Nuclear Site Services
- Blount, R., Superintendent of Maintenance
- Boehling, R., Maintenance Manager
- Butrick, P., Radiation Protection
- Christian, 0., Station Manager Collins, J., Director, Nuclear Emergency Preparedness
- Costello, J., Station Coordinator, Emergency Preparedness
- Cramer, R., Nuclear Site Services
- Cross, R., NS&L, Procedures
- Dahn, 0., Inservice Inspection, NOE
- Dooley, B., Maintenance Mechanical Group Supervisor Erickson, 0., Superintendent of Radiation Protection
- Farhner, 0., Senior Staff Assistant
- Garber, B., Licensing Garner, R., Outage and Planning Grainer, K., State Programs Harrison, S., Senior Emergency Planner Hayes, D., Supervisor of Administrative Services Haynes, G., Security Control Systems Operator Jones, M., Senior Office Associate Kansler, M., Vice President, Nuclear Engineering and Services Kulp, R., Coordinator, Emergency Planning Lovett, C., Supervisor, Licensing Luffman, C., Superintendent, Security Madison, W., Staff Emergency Planner
- McCarthy, J., Assistant Station Manager, Operations and Maintenance
- McConnell, F., Materials
- McGinnis, J., Station Nuclear Safety
- Medlin, G., Maintenance, Welding
- Miller, D., Radiation Protection
- Miller, G., Corporate, Licensing
- Moore, W., Operations
- Noce, 0., Radiological Engineer O'Hanlon, J., Senior Vice President, Nuclear
- Patrick, J., Training Phillips, T., Emergency Planner
- Renz, W., Staff Emergency Planner
- Ringler, M., Engineering Saunders, R., Vice President, Nuclear Operations
- Savage, K., Maintenance
- Savedge, R., Security.1 *
- Shriver, B., Assistant Station Manager, Nuclear Safety and Licensing
- Sloane, K., Superintendent of Outage and Planning
- Small, M., Nuclear Oversight
- Sommers, D., Supervisor, Licensing - Corporate
- Sowers, T., Superintendent of Engineering Stanley, B., Director, Station Nuclear Oversight
- Steed, T., Radiation Protection Swientoniewski, J., Supervisor, Station Nuclear Safety
- Thompson, G., Maintenance Wood, 5., Senior Instructor, Training Other licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation, and corporate personne PLANT OPERATIONS (40500, 71707)
The inspectors conducted frequent tours of the control room to verify proper staffing, operator attentiveness and adherence to approved procedure The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance with TSs and to maintain overall facility operational awarenes Instrumentation and ECCS lineups were periodically reviewed from control room indications to assess operability. Frequent plant tours were conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs and housekeepin Deviation reports were reviewed to assure that potential safety concerns were properly addressed and reporte Plant Status Unit l operated at 100% reactor power until February 2, when power was reduced to 81% to perform turbine inlet valve freedom testin Power was intermittently raised and lowered as necessary to reseat several turbine crossunder safety valves (paragraph 3.5). Full power was restored on February Unit 2 operated at full power for the entire report perio Loss of Missile Protection for the IA ESW Pump At 2:50 p.m. on January 17, the licensee determined that the soil that provides missile protection for the 24-inch IA ESW pump discharge line had been removed to a depth of 5.5 feet. This left approximately 6 to 12 inches of soil cover on top of the discharge piping. A minimum of 5 feet of soil cover is required to provide adequate missile protection. Missile protection is required for possible tornado events..
The soil had been removed December 13, 1995, to allow replacing the Unit I fish screen pump discharge pipin The IA ESW pump was declared inoperable at 2:50 p.m., based on the loss of missile protection and a 7 day action statement was entered per TS 3.1 * **.
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A field change to the fish screen pump discharge p1p1ng replacement design package was implemented to describe contingency actions required in the event of a tornado watc These actions included prestaging a load of gravel at the job site and providing a dedicated operator to fill the excavation in the event of a tornado watc Based on these actions, an engineering evaluation determined that the IA ESW pump was operable and the pump was declared operable at 8:00 p.m. on January 1 The inspectors reviewed the compensatory actions and found them adequate to address the immediate operability concer The licensee initiated a category 2 RCE and plans to issue an LE The inspectors will review this item further during review of the licensee's LE Operations of the Turbine Load Limiter On January 30, the inspectors noted that the Unit 2 TLL was set at approximately 97% as indicated on the turbine governor valve Position Limit mete Step 5.5.22 of procedure 2-GOP-1.5, Unit Startup, 2%
Reactor Power To Max Allowable Power, revision 10, requires that the TLL be set approximately 2 to 3% above the maximum allowable power leve The step further states that at 100% power, the TLL should indicate approximately 92 to 93% as shown on the Position Limit mete The Unit 2 RO was not aware of the GOP 100% power limit for the TLL settin The inspectors discussed this issue with the S The inspectors were informed that procedures 1&2-GOP-1.5 appeared to be incorrect and had not been upgraded to the new values established during the core uprate The SS instructed the operator to properly set the load limiter and initiated action to correct the procedure The DCP packages associated with the core uprate did not reference 1&2-GOP-1.5 as being impacted by the design chang In addition to reviewing the listing of affected procedures in the DCP package, the procedures group is required to do a computer word search of archived procedures as wel It appears that both of these processes missed the need to modify 1&2-GOP-1.5 as a result of the core uprat During discussions with the procedures group, two items were pointed ou First, the required action of the step in 1&2-GOP-1.5 was to set the limiter approximately 2 to 3% above the GV position and the 92 to 93%
was only a referenc Second, approximately 200 procedures were successfully modified as a result of the core uprate and that the misse procedures were an isolated cas During the inspector's observation in the CR, the limiter was limiting valve movement even though it was not set at the 92 to 93% valu The inspectors considered this item as an isolated example of not updating procedure *
Self Assessment The inspectors reviewed RCE 95-2912, Elevated SG Sodium and Chloride Level This RCE was initiated as the result of exceeding SG water chemistry Action Level II requirements when performing the Unit 1
moisture carryover test in December 1995. This event was addressed in Inspection Report Nos. 50-280/95-23 and 50-281/95-23. The RCE determined that the controlling procedure did not address critical parameters for the test and lacked guidance on the sampling frequency for sodium and chloride so trends involving water chemistry could be determine The RCE also determined that technical inaccuracies allowed incorrect concentration factors to be used to estimate the expected increases in sodium and chloride levels during the tes Two recommendations resulted from the RC These were: 1) Revise the moisture carryover test procedure to keep the condensate polishers in service and perform additional sampling, and 2) Evaluate and trend key SG chemistry requirements anytime SG blowdown or the condensate polishers are secure Both of the recommendations were accepted by station managemen The inspectors determined that the RCE was thorough and implementation of the recommendations should prevent recurrenc No violations or deviations were identifie.0 MAINTENANCE (61726, 62703, 71500, 92700, 92902)
During the reporting period, the inspectors reviewed the following maintenance and surveillance activities to assure compliance with the appropriate procedures and TS requirement.1 Preventive Maintenance on Valve l-CH-MOV-1269B 3.1.1 Mechanical Maintenance The inspectors observed licensee maintenance activities for motor operated valve l-CH-MOV-1269B in the B CCP suction line. This valve was scheduled for maintenance during plant operation The procedure used for this maintenance was O-MPM-0300-01, Limitorque Operator Type SB, SBD, SMB, and HBC Lubrication and Inspection, revision Specific attributes reviewed by the inspectors were the following: valve stroke; operator housing grease sampling and fill; operator fastener and hardware check; spring cartridge check for the Limitorque operator; stem and stem nut lubrication and check; valve packing area check; and follow-o No cracks, leaks, damage, or corrosion/erosion were foun The valve was in good mechanical condition and the maintenance was accomplished in a satisfactory manne.1.2 Electrical Maintenance The electrical maintenance and inspection for the valve operator identified that electrical wire in the limit and torque switches had broken leads, broken strands, and cuts in the insulation. The inspectors observed the replacement of the broken wire and determined that the work was performed adequately.
- Unit 1 A CCHx Cleaning and Modification 3.2.1 Modification of Associated Vent Pipe and Supports The inspectors inspected and reviewed the modifications on two I-inch diameter vent pipes and associated supports at the inlet and outlet end bells (east and west end bells}, also called exchanger channel ends, of CCHx 01-CC-E-I The vent pipes and supports were being modified and relocated to allow better access to the isolation valves. The WO for the modification was 0026474-0 The procedures for the modification were Section SUl-0006, Installation of Piping and Mechanical Equipment, revision 2, and O-MCM-1801-01, Piping, Components Repair and Replacement, revision Several isolation valves were repositioned to prepare for vent pipe modification and end bell coating. The inspectors verified proper valve positions and taggin The existing support for the inlet vent pipe was cut and taken to the maintenance shop for modificatio The inspectors observed cutting, grinding, leveling~ fit-up, and welding for this support and also verified that the applicable modification drawing was available in the shop and that the QC inspector was present to observe the activities and signed the data sheet After support modification, the inspectors observed satisfactory reattachment of the support to the heat exchanger and pipin The activities witnessed by the inspectors included measuring, cutting, grinding, fit-up, and weldin With respect to welding, the inspectors verified that fire watch personnel were on duty when the welding was in progress and remained at the job site for 30 minutes after the work was complete The inspectors reviewed records and data filled in on the applicable WO and procedures. The record and data included socket/fillet weld data, material types, heat numbers, welder identifications, weld procedure techniques, QC signatures for fit-up and final product.2.2 Removal of Valve l-VP-PCV-107 The inspectors witnessed the removal of vacuum priming valve l-VP-PCV-10 This valve is located in the inlet to the rerouted vent p1p1n Since the pipe and supports were rerouted and modified, the maintenance personnel decided to disassemble the valve flanges and pipe to inspect them for corrosion, erosion, or any damag Maintenance craft disassembled and inspected the flanges and found corrosion in the pipe flang Corrosion samples were provided to engineering for evaluation and determination of corrosion type and corrective action to be take Before the flanges were disassembled, the inspectors questioned whether this work was described in the WO and which procedure would be use Maintenance personnel replied that valve removal and flange inspection
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was within the scope of this modification package and that detailed instructions were not contained in the W Later, the inspectors addressed the same questions to the maintenance superviso He said that the flange disassembly in the WO did not need a procedure and that this work was considered skill-of-the-craf At the time, the inspectors were informed that procedure O-MCM-1004-01, Flange Gasket Replacement, revision 3, would be used to reassemble the flanges. After the flanges were disassembled the inspectors found, through further review, that this procedure not only contained the requirements, process, and records for the reassembly of the flanges but also contained the same steps for the disassembly. Sections 6.2 and contained the applicable steps for flange disassembly and reassembly, respectively. It appeared that maintenance personnel disassembled this flange without the procedur It also appeared that maintenance activities for this flange were not contained in the WO and were added in later. Later, the mechanical supervisor did state that the planner forgot to put the flange disassembly step in the WO as he had requested and that maintenance personnel did not have the procedure in the field when they performed the disassembly. Records, though, were immediately annotated in the shop after the disassembly was complete The inspectors determined that the disassembly was performed in a satisfactory manne The inspectors determined that maintenance planning and work controls for this WO were weak, in that, procedure O-MCM-1004-01 was not referenced for flange reassembly and use of skill-of-the-craft for flange disassembly was not clearly understoo Based on other work observed, this appeared to be an isolated weaknes.2.3 Cleaning and Coating CCHx End Bells The inspectors reviewed the cleaning and coating of the CCHx end bell The cleaning was conducted using procedure 0-MCM-0812-01, Bearing Cooling (BC} and Component Cooling (CC} Heat Exchanger Cleaning, revision 2, and WO 00316710-0 The inspectors verified that debris and foreign materials were adequately removed from the end bells in accordance with the procedur The inspectors reviewed the inspection of the end bells prior to preparation and coating. The licensee had previous experience repairing and coating end bells based on work on the other heat exchanger Procedure GMP-C-114, Cleaning, Repair, and Coating of Immersion Service Systems, revision 2, was used for end bell preparation and coating applicatio The end bell inspections identified a small corrosion area around the intersection of the titanium tube sheets and carbon steel flange of the main channel at the east end of the heat exchanger. Several spot corrosion areas approximately I-inch diameter and 1/4-inch deep in the flange area of the west end bell were also identifie The corrosion was determined to be galvanic and the flange area was not coated with a protective barrier coating syste The exposed carbon steel surface of the end bell flange coupled to the titanium tubes and tube sheets had
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established a strong galvanic cell and resulted in preferential galvanic corrosion of the more active carbon steel in the form of large localized pitting. The licensee decided to remove the corrosion and coat the east end bell and weld repair the corrosion and coat the west end bel After the inspection and repair, the inspectors observed the preparation and coating for the east end bell. First, the corrosion at the east end bell was removed with a wire brus An elastomer conditioner was then applied to form a thin layer on the metal. A solidified base component mixture was then applied as a coating on the intersection area of the carbon steel and the titanium sheets. The inspectors reviewed the required data recorded for Attachment 3 to Procedure GMP-C-11 The data included a confined space work permit, a coating permit, surface cleaning, surface preparation, power blast, coating materials, coating mixed time, and QC signature. The inspectors determined that the procedure was conducted adequately and that the assigned QC inspectors inspected the activity appropriatel.2.4 Flood Watch The inspectors observed flood watch activities during the opening of the end bells for cleaning and coating. Procedure No. OC-48, Assessment of Maintenance Activities for Potential Flooding of Turbine Building &
Associated Areas, revision 3, requires a flood watch when any work performed in the turbine building would generate an opening larger than two inches in diamete The flood watch was present at all times that the manway was not secure Unit 1 Incore D Flux Detector Assembly Troubleshooting Engineers perform core flux maps using the movable incore flux detectors on a monthly basis during power operation to verify core hot channel factors are within TS required limits. Following the Unit 1 startup in October 1995, the D incore detector 5 path assembly box would not rotate. Engineers were able to complete the required flux map using the remaining four incore detector assemblie However, one additional detector failure could make it impossible to perform a full flux map and thereby necessitate a reactor shutdown. Therefore, it was prudent to evaluate and repair the D incore detector assembl The inspectors evaluated troubleshooting activities to determine whether corrective maintenance was effectively implemente Technicians established WO 32866702 and prepared a troubleshooting plan in accordance with VPAP 2002, Work Requests and Work Order Tasks, revision 5-PSl to repair the D incore detector. Components which could cause the 5 path assembly box to fail were clearly identified. Initial maintenance activities confirmed that components located within the control cabinets outside of containment were functioning properl The troubleshooting plan was next updated to inspect the 5 path assembly box clutch, indexer, and motor located inside containmen The inspectors reviewed vendor manual 38-W893-00046, Technical Manual for In-Core Instrumentation, revision 1, and discussed the troubleshooting plan with
- technician The vendor manual provided clear, current drawings to support troubleshooting. Technicians were knowledgeable and the troubleshooting plan was well thought ou On January 10, technicians entered containment and determined that the 5 path assembly motor was damage The clutch and indexer appeared normal, but their operability could not be verified while inside containment with the motor inoperabl The inspectors discussed the motor replacement plan and procurement lead time with planning and maintenance personnel. Technicians concluded that it was impractical to repair the 5 path assembly at its mounted location inside the subatmospheric containmen Procurement engineers determined that the replacement motor had a 14 week delivery lead tim The inspectors noted that the 5 path assembly removal was not scheduled and discussed this with the Maintenance Superintenden The Maintenance Superintendent informed the inspectors that the repair schedule was under revie He planned to remove the 5 path assembly from containment early enough to permit further troubleshooting prior to the replacement motor's on-site arriva Planners began work with technicians to develop a work plan to perform 5 path assembly repairs outside containmen The inspectors concluded that repair efforts for the D incore detector 5 path assembly box were appropriate.
The inspectors attended the pre-job RWP briefing to determine whether recent RWP implementation weaknesses were addresse The briefing was detailed. Post job dose assessments including neutron whole body and skin dose calculations were properly documente Corrective actions to improve RWP comprehension, RP coverage within containment, and stay time assessment were effectively implemented for this work activit Unit 1 TDAFW Pump Governor Stem Movement Check In 1994, the licensee experienced corrosion and stem binding on the TDAFW pump governor valve stem The existing stems were replaced with chrome stems and a periodic stem movement check was established to evaluate stem freedo On January 21, the inspectors observed O-MPM-1403-03, Terry Turbine Governor Valve Stem Movement Check, revision 3, performanc The PM was properly performed under the direct supervision of a maintenance enginee TDAFW pump unavailability for this PM was limited to 15 minute O-MPM-1403-03 is performed monthly to support trending and assessment of stem freedom with the new type of stems installed. The inspectors reviewed the PM results and 1995 trending data with the maintenance enginee Both stem breakaway torque and full stroke torque have remained relatively constant with no indication of movement degradation since the chrome type stems were installed. The maintenance engineer indicated that PM periodicity was being reevaluated based on the data observed to dat The inspectors concluded that the PM was properly implemented and evaluated to monitor TDAFW pump governor stem freedo *.6
Unit I Turbine Inlet Valve Freedom Test Turbine inlet valves remain in a relatively motionless open position for prolonged periods when the turbine is online. Stuck open valves following a turbine load reject could lead to catastrophic turbine failure and turbine missile hazard UFSAR section 14.2.13 specifies that turbine inlet valves are exercised periodically during unit operation to reduce the possibility of valve stem stickin UFSAR section 10.3.1.2 further describes the crossunder stop and intercept valves which function to control turbine overspee Six safety valves are installed on each crossunder line to protect the MSRs and crossunder lines from overpressurization. The inspectors reviewed l-OSP-TM-001, Turbine Inlet Valve Freedom Test, revision 5, interviewed personnel, and evaluated test records to determine whether the turbine inlet valves and crossunder safety valves were properly tested and maintaine On February 2, the A MSR crossunder intercept and stop valves {Ill and lRl) failed to close during the quarterly performance test, l-OSP-TM-00 In addition, several crossunder safety valves lifted and failed to fully reseat. Engineers determined that misaligned contacts in the test circuitry caused the Ill intercept and lRl stop valves to remain ope Engineers implemented a procedurally controlled temporary modification to bypass the misaligned test contacts. The inspectors reviewed control circuit drawings with the system engineer and determined that the temporary modification was adequate to support valve closure testing. Additionally, the inspectors verified that the failure was isolated to the test circuit and normal valve closure was not affected. The turbine inlet valve freedom test was successfully performed on February 11. A work request was initiated to adjust the test circuit contacts when plant conditions permi On February 3, operators reduced power to 90% in efforts to reseat several partially open crossunder safety valves which failed to fully reseat when performing l-OSP-TM-00 The inspectors observed control room operations during the subsequent power ascension to 100%.
Full power was restored in a controlled manne Maintenance personnel gagged two crossunder safety valves which failed to fully reseat. Safety evaluations were performed to assess gagging the two safety valve The inspectors determined that the safety evaluations were technically soun The crossunder safety valves are tested during refueling outages at five year intervals. Maintenance personnel confirmed that the crossunder safety valves had been successfully tested within the program
. periodicity. The two gagged safety valves have been scheduled for testing and evaluation at the vendor's facility during the next refueling outag The inspectors concluded that the turbine inlet valves and crossunder safety valves were properly tested and maintained in accordance with the UFSA Planned Unit I TDAFW Pump and Valve Repacking On February 7, the TDAFW pump was tagged out to repack the pump and the steam supply valves.* The planned TDAFW pump outage period was ten
hour Post maintenance operability testing began approximately seven hours later than originally planne The inspectors determined that maintenance and operations personnel did not effectively coordinate activities to complete work and clear tags for testing in a timely manne The inspectors observed 1-0PT-FW-003, TDAFW Pump l-FW-P-2, revision 6, and 1-0PT-FW-007, TOAFW Pump Steam Line Check Valve Test, revision PT-FW-003 was performed as a post maintenance operability test for the TDAFW pump and the steam supply valve PT-FW-007 was performed to accomplish quarterly inservice testing program requirements for the steam supply line check valve The procedure tested the steam supply line check valves in the open direction, but not the closed directio The inspectors reviewed ISi program relief request V-42 and confirmed that l-OPT-FW-007 was consistent with the NRC approved Surry ISi progra Both tests were successfully completed in a professional manne The inspectors verified that the system configuration including flow instrumentation, steam supply valve controls, and required TDAFW pump flowrate were consistent with that described in UFSAR section 10. An onshift SRO provided close oversight during the post maintenance testing. Although the performance test acceptance criteria was satisfied, the SRO determined that the TDAFW pump inboard seal leakoff remained excessive. A work request was promptly initiated to repack the pump a second tim Following the repack, the inboard seal packing emitted heavy smoke when operators ran the pump to run in the packin The inspectors questioned why the first two pump repacks were unsuccessful and observed work activities when mechanical maintenance personnel repacked the TDAFW pump the third time. A different mechanical crew was assigned to repack the pump this tim The mechanics quickly determined that the packing installation sequence used during the first two attempts had been incorrect. The stuffing box cooling water inlet had been covered by a packing ring instead of aligning the lantern ring with the cooling por The work plan job step instructions were inconsistent with the pump packing procedure contained in the work packag Mechanics had properly questioned this discrepancy the first time the pump was repacke However, resolution to their question was incorrect and as a result the pump was unsuccessfully repacked twic The inspectors observed that the pump was properly repacked in accordance with WO 330595-0 Mechanics demonstrated good proficiency and completed the final pump seal repacking task promptl The TDAFW pump is an important component with regard to accident mitigation. Surry PRA analysis can be adversely effected if TDAFW pump reliability and availability are not properly maintaine The TDAFW pump was unavailable 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> beyond the originally planned outage perio The inspectors noted that the majority of this delay resulted from work planning and coordination problems which included clearing tags. The conflicting work instructions contained in the WO for repacking the TDAFW pump were identified by the first work crew, but were not properly resolve The maintenance rule pilot program
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generated a DR to evaluate the causes for the unplanned outage time for this key componen Management clearly expressed their concern that this work activity did not meet expectations and established a task team to review this work activity in detai The inspectors discussed their observations with station management and concluded that management had initiated appropriate action to investigate the work planning and coordination weaknesses which occurred during this planned work activit TS 6.4 requires detailed written procedures and instructions for corrective maintenance which has an effect on reactor safet VPAP-0801, Maintenance Program, revision 5, and VPAP-2020, Work Request and Work Order Task, revision 5-PS3, provide guidance to prepare and implement WO Failure to correctly resolve the work instruction conflicts for repacking the TDAFW pump prior to continuing work constitutes a failure to comply with TS 6.4, VPAP-0801, and VPAP-200 This licensee identified and corrected violation is being treated as a Non-cited Violation, consistent with Section VII.B.1 of the NRC's Enforcement Policy. This NCV is identified as NCV 50-280/96-01-02, Inadequate Resolution of TDAFW Pump Work Instruction Discrepancie Unit 1 Isophase Bus Duct Grounding Strap Temperature Monitoring On January 28, the inspectors noted that temporary cooling fans had been installed in the Unit 1 T These fans were connected to flexible ducting and were directed toward the B-Phase isophase bus duc The inspectors questioned the operating crew as to the need for temporary cooling of this bus duc The STA informed the inspectors that the grounding straps across one of the B-Phase isophase bus duct joints was significantly hotter than the others. The normal temperature of surrounding grounding straps was approximately 120 degrees However, the temperature of one of the straps was 370 degrees These temperatures had been closely monitored for several month The inspectors accompanied the STA to the TB and monitored the STA measuring the grounding strap temperature An infra-red temperature monitor was use The licensee's close monitoring of this degraded equipment was appropriat Open Item Followup Review 3.8.1 (Closed) LER 50-280/93-13, Volume Control Tank Level Decrease Results in Excessive Reactor Coolant System Leakag This LER describes a brief loss of RCS inventory during an ion exchanger resin transfe On November 17, 1993, leakage past a two-inch manual isolation valve caused VCT level to decrease unexpectedl Operators estimated the leak rate to be greater than 25 gallons per minut Operators took prompt action to secure the resin transfer and isolate the leak within two minute Leakage was contained within the low level liquid waste system and did not result in any increased health risk to the publi The leaking valve was promptly repaired. A failure evaluation determined that excessive corrosion products caused the
carbon steel spindle to bind, precluding valve closure. Maintenance engineers recommended refurbishing certain isolation valve bonnet assemblies with stainless steel component The inspectors determined that one corrective action to evaluate requirements for periodic maintenance/replacement of similar critical diaphragm valves had been prematurely closed without being performe Following discussions with the inspectors and maintenance engineers, licensing personnel opened CTS 3333 to perform this corrective actio The inspectors verified that all other corrective actions including isolation valve repair and procedure revisions to leak test the subject isolation valve were properly implemente The LER appropriately addressed the reporting criteria specified in 10 CFR 50.7.8.2 (Closed) IFI 50-280, 281/89-25-02, Anchor Bolt Interaction In Support Calculation This item involved the interaction ratio combining shear and tension of anchor bolts which was preliminarily determined to be 1.66 including a bending moment induced by a vertical loa The concern was that this 1.66 calculation was greater than the 1.0 ratio allowe Pipe Support Calculation No. 14937.53-NZ(B)-005-ZB-007 for Pipe Support No. H-34 did not consider the bending moment induced by the vertical load acting on the center of the top angle leg which would generate tension on the expansion anchor bolts. The calculation performed by Stone & Webster Engineering Corporation used a very conservative allowable shear of 1000 lbs for 1/2-inch diameter Hilti Kwik Bolts to check the shear onl The tension of the anchor bolt created by the bending moment from the vertical load was neglecte The reason for the omission was that the design engineers assumed that the vertical load would act on the shear center and would not induce a bending momen In their evaluation of this issue, the licensee claimed that the allowable loads used by Stone & Webster were too low and too conservative and that, based on current design criteria, the anchor bolt would be acceptable with the consideration of the bending momen The inspectors reviewed the following references provided by the licensee and discussed the item with engineering:
(1)
An evaluation contained in an attachment to SCARF 89-0128-001 for this IF (2)
Civil Engineering Standard No. STD-CEN-0024, Simplified Analysis of Base Plate Assemblies Utilizing Drill-In Concrete Anchor Bolt (3)
Hilti Anchoring Systems Catalog H-004A Published September 1988
{4)
Load versus Displacement Test for Hilti Kwik Bolt Concrete Expansion Anchors Performed at Surry Power Station on January 14 to 17, 1980
{5)
Allowable Loads and Design Criteria for Drilled-In Concrete Anchors By Stone & Webster Engineering Corporation The allowable loads of tension and shear for 1/2-inch diameter anchor bolts in Reference (5) are 1000 lbs eac Reference {2) lists the allowable loads as 2375 lbs for tension and 2310 lbs for shear at
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4000 psi concrete strength which were based on the Surry Site Test shown on Reference (4). Reference (3) lists the allowable load to be slightly low when comparing to Reference (2).
Based on review of the above references, the inspectors agreed with the licensee's evaluation and conclusion that the interaction ratio, considering the bending moment, is less than the allowable of 1.0 and is acceptable by using the current design criteri No violations or deviations were identifie.0 4.1 ENGINEERING REVIEW (37551, 92903}
Incorrect Feedwater Flow Instrument Span Used in FFR based FLOWCALC Program
- On November 7, 1995, engineers identified that the FW transmitter spans used in the Unit 2 FFR based FLOWCALC program, version 6.1, were less than actually present in the plant. This resulted in the FFR based CALCALC program using less than actual FFR when calculating reactor powe The licensee initiated DR S95-2703 and PPR 95-028 to determine the cause and potential impact of the discrepancy and correct the FFR based FLOWCALC program FW transmitter span value As previously discussed in NRC IR 50-280, 281/95-19, operators have used the FFR based CALCALC to determine reactor power since the Unit 2 core upgrade in August 199 The inspectors questioned whether the unit had been operated above the 2546 MWT (100.0% rated power} licensed limit due to this nonconservative FW flowrate error. Engineering initiated ET NAF-95161, Impact of Channel Span Input Error FFR based in FLOWCALC Offsetting Effects of Assumed Moisture Carryover Surry Power Station -
Unit 2, revision 0, to evaluate this concer Engineering determined that the impact of underestimating FW flowrate had been fully offset by using a conservative steam enthalpy, with 0%
moisture content, in the FFR based CALCALC progra Recent testing indicated that actual Unit 2 moisture carryover is greater than or equal to.223%.
The inspectors discussed ET NAF-95161 with engineering and independently calculated the effects of the incorrect FW instrument span used in the FLOWCALC progra The incorrect span caused reactor power to indicate approximately 0.18% lower than if the correct span was installed. The conservative moisture carryover assumption caused reactor power to indicate approximately 0.20% higher than if actual steam enthalpy was use The inspectors concluded that ET NAF-95161 was technically sound and that Unit 2 did not operate above the power levels permitted by T The inspectors verified that the FLOWCALC program was updated to use the correct FW flow instrument spans on November 16, 1995, prior to Unit 2 startup from a forced outag The licensee determined that the Unit 2 FW flow transmitters spans were updated in February 1993 in accordance with calculation EE-0375, revision The FFR based FLOWCALC program was not updated and continued to use the span values specified in EE-0375, revision The
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inspectors noted that this event was similar to a March 1994 event during which Unit l exceeded rated core power limits. Although corrective actions to the 1994 overpower event failed to identify this discrepancy, reactor power remained below the licensed limi The inspectors interviewed reactor engineers and licensing representatives to determine why the Unit 2 FFR based FLOWCALC program error wasn't identified and corrected when corrective actions to the March 1994 overpower event were implemente One of the overpower event corrective actions, CTS 2694, was established to review other safety-related instrumentation to verify that parameters affected by previously implemented scaling revisions were consistent with the current calculations, design documents, procedures, computer programs, and installed equipment. This action was developed to ensure any discrepancies which may have originated prior to the March 1994 event were identified and correcte Corporate engineers had performed a detailed review of calculation and scaling changes and documented their results in ET CEE 94-040, revision This review determined that there were no other loops or components which required change as a result of calculations or scalin ET No. CEE 94-040 was performed through personnel interviews and record reviews at the corporate level. The inspectors determined that the intended verification that scaling values calculated by corporate engineers were actually installed on station equipment was not performe The inspectors concluded that miscommunication between the Design Engineering & Support and Licensing departments directly resulted in the premature closure of CTS 2694 and failure to identify the Unit 2 FFR based FLOWCALC discrepancy. Reactor engineers informed the inspectors that DR S95-2703 and a Category 2 RCE will specifically address the premature CTS item closure and associated interdepartmental miscommunication CFR 50, Appendix B Criterion XVI, Corrective Action, requires measures to be established to assure conditions adverse to quality be promptly identified and corrected. Ineffective FLOWCALC design control previously resulted in a March 1994 overpower event (VIO 50-280/94-11-0l). Corrective actions to that event failed to identify and correct a similar pre-existing calorimetric program discrepancy on Unit The incomplete corrective action resulted in Unit 2 continuing to operate with an incorrect FW flow transmitter span input to the FLOWCALC program until November 16, 199 The failure to promptly identify and correct the deficient Unit 2 FLOWCALC condition is identified as VIO 50-281/96-01-0l, Failure to Promptly Identify and Correct Deficient Unit 2 FLOWCALC Conditio Crossunder Safety Valve l-MS-SV-109B Temporary Modification The inspectors reviewed the safety evaluation performed to allow gagging crossunder safety valve l-MS-SV-109 The valve is one of 12 safety
valves located on the piping between the high pressure turbine and the low pressure turbines and had begun lifting with the unit stable at 100%
power following completion of the turbine valve freedom test. The purpose of the safety evaluation was to determine if the safety valve could be gagged to allow the unit to be returned to 100% powe The safety evaluation determined that with l-MS-SV-109B gagged the system would still be capable of relieving 100% steam flo The inspectors determined that the safety evaluation adequately justified the temporary modification to gag the crossunder safety valv.3 Open Item Followup Review The inspectors reviewed applicable licensee's updates and responses to previously identified regulatory issues, as well as, LERs submitted to the NR The purpose of this review was to verify description accuracy, determine generic applicability and cause, and to evaluate any precursor events and the effectiveness of corrective action In addition, applicable LERs were also reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022, Licensee Event Report System, and its associated supplement {Closed) VIO 50-280/94-11-01, Failure to Revise the Steam Flow Calorimetric Computer Program Engineers failed to update the Unit 1 SFR based FLOWCALC computer program to incorporate steam flow instrument scaling modifications which were implemented during the March 1994 refueling outage. This resulted in reactor operation above the licensed power limit. The event was detailed in LER 50-280/94-0 The inspectors reviewed records and interviewed personnel to assess corrective action effectivenes The violation response, dated September 16, 1994, described planned corrective actions to preclude event recurrence. Actions included modification to the instrumentation change control process, training, change control process assessment, reactivity management control assessment, verification of previous scaling revisions, alternate means to verify reactor power after refueling, and quality assurance oversight for engineering calculation implementatio The inspectors noted that the corrective action plan was detailed and thoroughly addressed the causal factors which contributed to the overpower even Significant process improvements were gained by establishing VPAP-0303, Scaling/Setpoint Change & Curve Control Program, revision Existing procedures were revised to proceduralize requirements to obtain reactor engineer reviews for activities related to reactivity managemen Power ascension procedures were revised to require a hold point for reactor engineers to verify reactor power level using alternate power indications prior to exceeding 96% reactor power.
- The inspectors reviewed Nuclear Core Design Manual Part VII, Chapter N, Evaluation of Alternate Power Indications, revision This new instruction discussed the March 1994 overpower event and provided useful alternate power indication criteria for reactor engineers to evaluate during power ascensio The inspectors confirmed that reactor engineers had performed detailed alternate power indication evaluation to support the Unit 2 startup on November 23, 199 Reactor engineers demonstrated a strong understanding of alternate power indications and the variable plant conditions which may affect the indication The inspectors concluded that proceduralizing alternate power indication verifications during power ascension was an effective action to preclude future overpower event Setpoint and scaling changes are now required to be implemented using the OCP proces The inspectors reviewed the OCP process with reactor engineers and confirmed that the process provided appropriate controls for implementing setpoint/scaling change The inspectors concluded that the actions discussed above were complete and were appropriate to preclude future discrepancies from developing between controlled setpoint/scaling calculations and station installed value Weaknesses identified in the corrective action closure process which failed to identify a pre-existing feedwater span error are discussed in paragraph )~
One violation was identifie * PLANT SUPPORT (71750, 92701) Emergency Preparedness Program Review 5.1.1 Emergency Plan and Implementing Procedures This area was inspected to determine whether significant changes were made in the licensee's emergency preparedness program since August 1994 (when the last such inspection of this area was performed), to assess the impact of any such changes on the overall state of emergency preparedness at the facility, and to determine whether the licensee's actions in response to actual emergencies were in accordance with the Emergency Plan and its implementing procedure Requirements applicable to this area are found in 10 CFR 50.47(b)(l6), 10 CFR 50.54(q),
Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla The version of the Emergency Plan in effect at the time of the current inspection was revision 40, which became effective on January 1, 199 Since the previously referenced August 1994 inspection, the NRC has formally reviewed and approved three revisions to the Emergency Plan. A review of licensee records indicated all revisions to the Emergency Plan continued to be of high quality and were transmitted to the NRC within 30 days of the implementation date, as required.
There was one SEP activation since the last inspectio It was a Notification of Unusual Event on November 25, 1994, based on a chemical
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explosion on site (later determined to be the rupture of a chemical reaction tank in the Radwaste Facility). The classification was conservative and a review of licensee documentation indicated notifications to both the offsite authorities and the NRC were made in accordance with applicable document.1.2 Emergency Response Facilities, Equipment, Instrumentation, and Supplies This area was inspected to determine whether the licensee's ERFs and associated equipment, instrumentation, and supplies were maintained in a state of operational readiness, and to assess the impact of any changes in this area upon the emergency preparedness progra Requirements applicable to this area are found in 10 CFR 50.47(b)(8) and (9),
10 CFR 50.54(q), Sections IV.E and VI of Appendix E to 10 CFR Part 50, and the licensee's Emergency Plan. *
The inspectors toured the TSC and EO Selective examination of equipment and supplies indicated that a high level of operational readiness was being maintained for these ERF No significant changes had been made to the facilitie The most significant equipment changes that had been made affected the offsite siren system, consisting of 61 sirens in the 10 mile EP By the end of November 1995, the licensee had installed an uninterruptable power supply to each of the siren activation points offsite, i.e., the Surry County EOC, the James City County EOC, and the Commonwealth of Virginia's DES EO New control panels had also been installed at each of the EOCs to assist in system monitorin The December 1995 quarterly test which was activated by the DES EOC was 100% successfu The improvements made to improve the siren system's reliability were considered a program strengt.1.3 Organization and Management Control This area was inspected to determine the effects of any changes in the licensee's emergency organization and/or management control systems on the emergency preparedness program, and to determine the effect of these changes on the licensee's overall emergency preparedness progra Requirements applicable to this area are found in 10 CFR 50.47(b)(l) and (16),Section IV.A of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla The organization and management of the emergency preparedness program were reviewed and discussed with licensee representatives. Although changes had been made to the management control of the program, they did not have an adverse impact on the progra For example, the Station Coordinator, Emergency Planning, now reports to the Director of Licensing instead of the Assistant Station Manager for Nuclear Safety and Licensing. Also, the QA department had been reorganized into a Nuclear Oversight Departmen Discussions with key personnel indicated this reorganization would not impact the independent audits of emergency preparedness in an adverse manne *
An additional organizational change was the assignment at Surry Power Station of a Coordinator, Emergency Planning and a Senior Instructor, both of which are personnel reporting to the Director of Emergency Planning in Innsbrook but with duties to support the Surry Statio This reorganization established designated positions to provide support previously made available but not under the direct control of emergency plannin Improvements to the EP program have already been seen in the ability to better coordinate training requirements to support offsite training need.1.4 Training This area was inspected to determine whether the licensee's key emergency response personnel were properly trained and understood their emergency responsibilities. Requirements applicable to this area are contained in 10 CFR 50.47(b)(2) and (15),Section IV.E of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla The inspectors reviewed selected records and discussed with cognizant personnel the training program for the ER The licensee continued to maintain a formal training program with emphasis on drill participation as an excellent means to improve ERO member's skill An apparent enhancement to the training program could be the implementation of facility drills that will focus on only one of the ERFs, thereby permitting greater interactive training with less impact on station personnel resources. This will also permit the key EP trainers to focus on one facility and allow for more frequent drills because of the reduced manpower requirement.1.5 Independent Audits and Internal Reviews This area was inspected to determine whether the licensee had performed an independent audit of the emergency preparedness program, and whether the emergency planning staff had conducted a review of the Emergency Plan and the EPIP Requirements applicable to this area are found in 10 CFR 50.54(t) and the licensee's Emergency Pla The inspectors reviewed the independent audit report and the annual review of the SEP and EPIPs by the EP staff. Both the audit report and review were thorough and fully met regulatory requirement Discussions addressing the independent audits led the inspectors to believe that an opportunity for improved audits may evolve from the reorganization of QA into the Nuclear Oversight Department. This should be possible because the same personnel conducting the audit of Surry Power Station will be team members for the North Anna Power Station and Corporate EP audit The opportunity for comparison of how the different staffs accomplish requirements should assist in identifying problems, as well as, provide the identification of the better way to do business.
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5.1.6 Effectiveness of Licensee Controls This area was reviewed to determine the effectiveness of licensee controls in identification of problems and then taking corrective action During the visit to the corporate office, the inspectors noted a customer survey that had been recently distributed to selected members of the Virginia Power ER The survey was to solicit comments from the ERO members regarding how well they thought the program was being managed and to ascertain their feelings regarding their comfort level to effectively accomplish their assigned tasks. The questionnaire consisted of approximately 20 statements that addressed the major functional areas of the EP program and required a rank ordered response for levels of strong agreement to strong disagreement with the statement The end results of this initiative were not yet availabl * However, effective use of the evaluated responses could provide an opportunity for using resources to improve the overall progra The inspectors identified this type of initiative as a program strengt Plant Tour Observations The inspectors observed radiological control practices and radiological conditions throughout the plant. Radiological posting and control of contaminated areas was goo Workers complied with RWPs and appropriately used required personnel monitoring device The protected area security perimeter was well maintained with no equipment or debris obstructing the isolation zone The inspectors observed that the fire barrier door which connects the Unit 1 and Unit 2 normal switchgear rooms was routinely open and supported by its blow-off chai The Surry fire protection program permits fire doors to be open and unattended if they are properly supported by their blow-off chain closure devic The inspectors confirmed that the blow-off chain closure devices had been successfully tested within their required periodicity. A closed fire barrier door is a passive safety devic An open fire door on its blow-off chain relies on an active safety device for closure. The inspectors questioned {l)
whether there was an operational reason for maintaining the normal switchgear room fire door open on its blow-off chain and {2) what the station policy was regarding when to use blow-off chains versus when to maintain fire barrier doors shu The operations SS informed the inspectors that there was not a current operational reason for maintaining the door ope Safety and fire protection engineers stated that, although not written, station policy is to maintain fire barrier doors closed unless there is an operational reason to place a fire barrier door open on its blow-off chain closure devic Fire protection
and safety engineers initiated action to clarify and promulgate this policy. The inspectors concluded that this action appropriately reinforced management's intention to rely on passive safety devices versus active safety devices when practica No violations or deviations were identifie.0 Review of UFSAR Commitments (61726, 71500, 71707)
A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and/or parameters to the UFSAR descriptions. During a portion of the inspection period (February 1-10, 1996) the inspectors reviewed the applicable sections of the UFSAR that related to the inspection areas discussed in this repor The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and/or parameter No violations or deviations were identifie.0 OTHER NRC PERSONNEL ON SITE None EXIT The inspection scope and findings were summarized on February 14, 1996, by M. W. Branch with those persons indicated by an asterisk in paragraph An additional inspection finding was summarized on March 8, 1996, with T. Sower Interim exits were conducted on January 12 and 19, 199 The inspectors described the areas inspected and discussed in detail the inspection results. A listing of inspection findings is provide Proprietary information is not contained in this report. Dissenting comments were not received from the license ~
Item Number LER 50-280/93-13 IFI 50-280, 281/89-25-02 Status Closed Closed Description and Reference Volume Control Tank Level Decrease Results in Excessive Reactor Coolant System Leakage (Paragraph 3.8.1).
Anchor Bolt Interaction in Support Calculation (Paragraph 3.8.2).
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Item Number VIO 50-281/96-01-01
Status Open Description and Reference Failure to Promptly Identify and Correct Deficient Unit 2 FLOWCALC Condition (Paragraph 4.1).
NCV 50-280/96-01-02 Closed Inadequate Resolution of TDAFW Pump Work Instruction Discrepancies (Paragraph 3.6).
VIO 50-280/94-11-01 Closed Failure to Revise the Steam Flow Calorimetric Computer Program (Paragraph 4.3.1). ACRONYMS CALCALC CCHx CCP CFR CR CTS DCP DES DR ECCS EOC EOF EP EPIP EPZ ERF ERO ESW F
FFR FLOWCALC FW GOP GV IFI IR ISi lbs LER MSR MWT NDE NRC NS&L PM SECONDARY CALORIMETRIC CALIBRATION COMPONENT COOLING HEAT EXCHANGER COMPONENT COOLING PUMP CODE OF FEDERAL REGULATIONS CONTROL ROOM STATION COMMITMENT TRACKING SYSTEM DESIGN CHANGE PLAN DEPARTMENT OF EMERGENCY SERVICES DEVIATION REPORT EMERGENCY CORE COOLING SYSTEM EMERGENCY OPERATIONS CENTER EMERGENCY OPERATIONS FACILITY EMERGENCY PLAN EMERGENCY PLAN IMPLEMENTING PROCEDURE EMERGENCY PLANNING ZONE EMERGENCY RESPONSE FACILITY EMERGENCY RESPONSE ORGANIZATION EMERGENCY SERVICE WATER FAHRENHEIT FEED FLOW RATE FLOWRATE CALCULATION FEEDWATER GENERAL OPERATING PROCEDURE GOVERNOR VALVE INSPECTION FOLLOWUP ITEM INSPECTION REPORT INSERVICE INSPECTION POUNDS LICENSEE EVENT REPORT MOISTURE SEPARATOR REHEATER MEGAWATT THERMAL NONDESTRUCTIVE EXAMINATION NUCLEAR REGULATORY COMMISSION NUCLEAR SAFETY & LICENSING PREVENTIVE MAINTENANCE
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PPR POTENTIAL PROBLEM REPORT PRA PROBABILISTIC RISK ASSESSMENT psi POUNDS PER SQUARE INCH QA QUALITY ASSURANCE QC QUALITY CONTROL RCE ROOT CAUSE EVALUATION RCS REACTOR COOLANT SYSTEM RO REACTOR OPERATOR RP RADIOLOGICAL PROTECTION RWP RADIATION WORK PERMIT SCARF STATION COMMITMENT ASSIGNMENT RESPONSE FORM SEP SURRY POWER STATION EMERGENCY PLAN SFR STEAM FLOW RATE SG STEAM GENERATOR ss SHIFT SUPERVISOR SRO SENIOR REACTOR OPERATOR STA SHIFT TECHNICAL ADVISOR TB TURBINE BUILDING TDAFW TURBINE DRIVEN AUXILIARY FEEDWATER TLL TURBINE LOAD LIMITER TS TECHNICAL SPECIFICATION TSC TECHNICAL SUPPORT CENTER UFSAR UPDATED FINAL SAFETY ANALYSIS REPORT
VCT VOLUME CONTROL TANK VIO VIOLATION VPAP VIRGINIA POWER ADMINISTRATIVE PROCEDURE WO WORK ORDER