IR 05000338/1993020
| ML20057C165 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 09/17/1993 |
| From: | Belisle G, Taylor D, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20057C163 | List: |
| References | |
| 50-338-93-20, 50-339-93-20, NUDOCS 9309280025 | |
| Download: ML20057C165 (10) | |
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NUCLEAR REGULATORY COMMISSION UNITED STATES
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101 MARIETTA STREET, N.W., SUITE 2900
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qp ATLANTA. GEORGIA 30323 0199
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Report Nos.:
50-338/93-20 and 50-339/93-20 Licensee:
' Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: July 18 - August 21 1993
/[/7N3 Inspectors:
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m J. W() fork, ActTf/Seni rAeside t inspector Date '51dned
.Cr 4f D. R' Tay1 r, Re eht Inspettor
'Date Sfgned
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Approved by:
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v//7[(/.T
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G. A.LBelisle, Sectio (Chief
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D)tb Signed l
Division of Reactor Projects l
SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas:
plant status, operational safety verification, maintenance observation, surveillance observation, and action on previous inspection items.
Inspections of licensee backshift activities were conducted on the following days: July 21, 27, 28 and 29.
Results:
In the operations area:
Adverse weather condition procedures were determined to be adequate.. Based upon reviews of lessons learned from hurricane Andrew, additional enhancements were being developed for incorporation into these procedures (paragraph 3.b).
In the maintenance / surveillance area:
A strength was identified for the licensee's promptness in inspecting the cladding on a second charging pump for degradation after the repair of another pump (paragraph 4.b).
A procedural weakness contributed to the auxiliary feedwater pressure control valve controllers not being set at their optimum values (paragraph 5.b).
i 9309280025 930917 f
PDR ADDCK 05000338 G
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w REPORT DETAILS 1.
Persons Contacted j
Licensee Employees L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager, Operations and Maintenance J. Hayes, Superintendent of Operations D. Heacock, Superintendent, Station Engineering G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing W. Matthews, Superintendent, Maintenance
- J. O'Hanlon, Vice President, Nuclear Operations D. Roberts, Supervisor, Station Nuclear Safety R. Saunders, Assistant Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Outage and Planning J. Smith, Manager, Quality Assurance A. Stafford, Superintendent, Radiological Protection
- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing
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Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
- J. York, Acting Senior Resident Inspector D. Taylor, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the
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last paragraph.
2.
Plant Status Unit 1 operated at or near 100% power the entire inspection period.
Unit 2 was in a coastdown for a scheduled September 6 refueling outage.
At the end of the inspection period, the unit was at approximately 75%
power.
l 3.
Operational Safety Verification (71707)
The inspectors conducted frequent visits to the. control room to verify
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proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
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operator logs.on a daily basis to verify operational safety and.
compliance with TS and to maintain awareness of. the overall operation of
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the facility.
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 housekeeping.
Deviation Reports were reviewed to assure that potential safety concerns were properly addressed and reported.
Selected reports were followed to ensure that appropriate management attention and-corrective action were applied.
a.
Monthly Quality Briefing The inspectors continued to meet monthly with QA personnel.
On July 28 the inspectors were briefed on activities that had been conducted by the quality organization in the area of audits, assessments, and QC inspections. Audits were performed in the emergency plan and technical specification areas.
No findings were identified in either audit.
The inspectors also discussed deviation reports written by QC inspectors, assessments performed
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in design change program, the procedures program, and work order implementation.
No concerns were identified and the briefing was beneficial.
b.
Adverse Weather Conditions The inspectors reviewed procedure number 0-AP-41, Severe Weather Conditions. This procedure provided general instructions to follow when severe weather conditions exist or are anticipated.
The procedure provided attachments for tornado watch, tornado warning, hurricane watch, hurricane warning, and hazardous i
weather.
Each attachment provided requirements for personnel notification, general watch standing, and securing loose.
equipment.
Furthermore, the procedure required performing an EDG load test when a hurricane watch occurs.
The inspectors also
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reviewed the licensee's emergency plan for declaring an emergency
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due to severe weather, EPIP-1.01 Attachment 1, Emergency Action
Level Table (Tab L) Natural Events.
The inspectors considered these procedures to be adequate.
On August 3, the inspectors met with corporate OER personnel to discuss the status of their review of lessons learned from Hurricane Andrew and any planned corrective actions. This report i
was being finalized and will be issued in late summer. A review was conducted of some of the preliminary results for upgrading i
abnormal procedure 0-AP-41 and evaluating the design basis for some structures and equipment. A draft advance planning policy involving circumstances outside abnormal procedures was also
reviewed. These plans when implemented will add considerably more
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planning and detail to the preparations.for hurricanes.
The-inspectors will continue to follow this project.
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c.
Control Board Walkdowns On July 30, during a control room board walkdown, the inspectors noticed that the Unit 2 "SI/CDA load shed DC power available" indicator light was not lit.
The condition was brought to the attention of the unit CR0.
An initial investigation concluded that the problem was not due to a burnt out light bulb.
Further investigation revealed that relay 74-2ENSJ08 had failed. The relay supplies one contact to the power available lamp circuit and did not effect control functions.
The inspectors reviewed applicable drawings to verify that the load shed circuit was not affected. The relay was replaced and power available indication returned to normal.
On August 2, while the licensee was performing a routine AFW pump surveillance test, the inspectors identified expired calibration stickers on AFW HCV valve demand indicators.
The inspectors discussed the valves' PM frequencies with I&C personnel who determined the PM frequency had been changed from once per cycle to once every other cycle per a RCM recommendation.
The inspectors verified that the calibrations were within the new recommended frequencies. The old stickers were removed and new stickers were installed.
The inspectors also reviewed the PM task evaluation request which changed the frequency based on the RCH recommendations. No concerns were identified with the extended frequency interval.
No violations or deviations were identified.
4.
Maintenance Observation (62703)
Station maintenance activities were observed / reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with TS requirements.
a.
Charging /HHSI Pump Failure
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On July 5,1-CH-P-lC charging /HHSI pump seal injection low flow alarms were received.
Subsequent review revealed that the pump was degrading as indicated by increasing current (amps),
decreasing discharge pressure, high vibrations, and low flow.
1-CH-P-1A was started and the C pump was removed from service for inspection and repair. As part of the maintenance scope, the pump rotating element was sent to the Westinghouse service center for repair.
Inspection of the element identified the following damage:
localized impeller scoring
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balance drum scoring a
an out-of-specif. ; tion berc shaft
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In addition, the pump discharge casing clad material showed erosion / corrosion indications (discussed further in paragraph 4.b).
Restoring the pump consisted of replacing both the rotating element shaft and an eleventh stage impeller.
During the l
restoration process, the licensee's maintenance engineering and
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corporate QA personnel provided oversight.
TS surveillance 4.5.2.h was required to be performed following completion of modifications to the ECCS subsystems that could alter the subsystem flow characteristics. The TS requires that for HHSI lines, with a single pump running, the sum of the injection line flow rates, excluding the highest flow rate, is greater than or equal to 384 gpm and the total pump flow is less than or equal to 650 gpm. These requirements provide a specified acceptance range of about 4%. The pump manufacturer provided the i
licensee with a letter stating that based on the work done to the i
rotating element, the pump should perform as shown on the original j
pump curve with a tolerance of + or - 3% at any capacity up to 650
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gpm.
Based on this data and the previously performed flow l
balance, the licensee determined that this value would be outside
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Because of the tighter than needed tolerances, the licensee had experienced previous problems meeting the TS flow balance requirements and had submitted a TS change to the NRC.
The proposed change decreases the allowable sum of the flows through the two lowest flow branch lines and increases the allowable total
flow.
The TS change would provide about a 9% acceptance range.
i On July 30, the inspectors observed performance of 1-PT-14.3, Charging Pump, 1-CH-P-lC.
In addition to the normal IST data i
taken during the surveillance, the pump was run at three points on i
the pump head curve.
Each point was at a low flow and in the horizontal portion of the curve.
The test results were satisfactory; however, the pump was removed from_ service pending the TS change (for broader flow balance requirements) and further review by the licensee. The licensee plotted the points they obtained and compared them to the original manufacturer's pump curve. The data indicated the pump was operating about 3% high, but it >.s consistent with recent IST data taken before the pump
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failure.
Based on the proposed TS change, restoration of the pump to its original. design specifications and the reduced flow testing
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that was performed, the licensee concluded that the pump should meet TS requirements when tested during the next refueling shutdown. At the end of the inspection period, the root cause of the pump failure was still under investigation.
On August 4, TS Amendments 171 and 151 for Units 1 and 2, respectively, were approved by the NRC with the larger acceptance range. On August 6,-1-CH-P-lC was returned to service and
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declared operable. The inspectors will review the root cause evaluation when issued by the licensee.
b.
Clad Repair on 1-CH-P-lc Using the pump vendor's bulletin / procedure No. 037-0-0104-0, Inspection of Chromium-Nickel Cladding 2-1/2" Type IJ ll-Stage Charging / Safety Injection Pumps, dated July 8, 1983, the licensee performed a visual and dye penetrant inspection of the cladding on the interior of the 1-CH-P-lC charging pump. This was the first time that this pump had been disassembled by the licensee, Upon visual inspection of the cladding, an area of rust was noted on the stainless steel cladding in the three-inch diameter discharge nozzle.
Cracks in the cladding allowed boric acid to attack the carbon steel base metal producing a highly visible rust area. During the repair, this area was ground out until all defects were removed. Defect removal was verified by visual and dye penetrant inspections.
The final dimensions of the ground out
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area were 2.5" long by 1.5" wide by 0.5" deep.
Both the base metal and the cladding were repaired using a gas tungsten arc welding process. The inspectors reviewed welding records in the areas of welder qualifications, weld metal, and nondestructive testing.
No discrepancies were noted.
Based on the as-found condition of 1-CH-P-lc cladding, 1-CH-P-1B was removed from service on August 9 (after 1-CH-P-lc was returned to service on August 6) for inspection and possible repair. A charging pump hLstory review indicated that the B pump had the highest number 6f run hours of the three pumps and would be more
susceptible to base metal attack if cracking were present in the cladding. The 1-CH-P-1A pump casing was stainless steel and therefore not subject to this type of degradation.
After removing
the rotating element for 1-CH-P-18, the inspectors observed
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maintenance engineers examining the pump suction and discharge areas.
The suspect areas were not easily inspected because of their location and required use of a mirror. Although the inspectors could not visually examine the entire area, there was no evidence of clad damage. This was based on the absence of rust formation and visible cracks.
Following the inspections, maintenance engineering released the pump for reassembly. The prompt action by the licensee to evaluate the cladding on the B
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pump after the C pump was declared operable was identified as a strength.
Due to unavailability of parts, inspection of the Unit 2 charging pump casings will not be performed until after the 1993 Fall refueling outage.
Parts to reassemble the Unit 2 charging pumps were anticipated to be available by mid-to-late November.
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c.
PG to Blender Valve Maintenance On July 21, the inspectors observed corrective maintenance on 01-CH-FCV-1114A, PG Water To Blender Control Valve. The maintenance was performed under WO 163496 using 0-MCM-0400-03, Rev. 3, Safety Related Air Operated Valves and MDAP 0019, Supplemental Work Instructions. The valve was suspected of leaking PG water past its seating surface which, over a period of time, was contributing to diluting the boron concentration in the boric acid storage tanks.
The inspectors observed disassembly of the valve and inspections of the valve disk and seating surface.
During the performance of the work, no discrepancies were identified.
The valve was apparently the dilution source because after the repair, no boric acid dilution in the storage tanks was observed.
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No violations or deviations were identified.
S.
Surveillance Observation (61726)
The inspectors observed / reviewed TS required testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that LCOs were met and that any deficiencies identified were properly reviewed and resolved.
a.
AFW Steam Driven Pump Test On August 6, the inspectors observed performance of 1-PT-71.1, 1-FW-P-2 Auxiliary Feedwater Pump Test.
The test is performed every 31 days to verify pump operability.
Specifically, the steam turbine driven AFW pump is run to verify that full flow recirculation test data meets requirements.
In addition the test verifies that each valve in the flow path which is not locked, sealed, or otherwise secured in position, is in its correct
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position. The inspectors verified that test data met acceptance
criteria by directly observing equipment and instrumentation.
During the test performance, the inspectors identified that the manual isolation valves upstream and downstream of 1-MS-TV-111A and 111B were not included as part of the procedure's flow path operability check. Steam to drive the turbine driven AFW pump is available through parallel air operated valves 1-MS-TV-111A and
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111B.
These valves can be isolated by manual valves 1-MS-268, 269, 270 and 271.
The inspectors discussed this condition with the licensee. System engineers defined the AFW flow path during a recent TS review process to include suction from the ECST, valve and piping alignment through appropriate pumps, with discharge to steam generators via the feedwater lines.
The MS supply header and i
valves were not considered to pertain to the TS requirement although one of the parallel steam paths could be isolated without indication in the control room and with the monthly PT being
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successfully performed.
During a review of the new Westinghouse
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standard TSs, it was noted that they specifically include the steam path as part of the 31 day surveillance. North Anna's TSs
do not explicitly include the steam flow path. The licensee revised the Unit I and 2 turbine driven AFW pump pts to include a-check for the position of these manual valves.
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b.
AFW HCV Valve Calibration On August 11, the inspectors discussed the performance of 0-lCP-MIS-G-001, Miscellaneous Instrumentation Calibration, with I&C personnel.
NRC IR 50-338,339/93-19 discussed as-found improper settings of AFW pressure control valves 259A and 2598. The reason for the valves being improperly set was determined, in part, to be an inadequate procedure. When calibrating a pressere controller, the proportional band and reset values can affect the controller's set point.
For most controllers after calibration, the controller is adjusted (tuned) on-line to the controlling setpoint.
However, for the AFW valves during normal AFW pump operation, pump discharge pressure is greater than the controller calibrated range and, therefore, on-line tuning is not possible.
To ensure the AFW controllers would properly respond, the procedures were modified to require as-found and as-left functional tests. Although, for this case, the AFW pumps were determined to be operable, the inspectors considered the procedures and setting of controllers for this application to be a weakness because the controllers would not be set at the optimum values.
No violations or deviations were identified.
i 6.
Action on Previous Inspection Items (92701, 92702)
(0 pen) Violations 50-338, 339/92-18-04 and 05:
Failure to Maintain
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Penetration Fire Barriers and Failure to Establish Adequate Fire Barrier Inspection Procedure
The inspectors reviewed the status of fire protection system fire barrier inspections completed in accordance with 0-PT-105.1.4B, Fire Barriers. NRC IR 50-438, 339/92-18 documented two violations involving the failure to maintain fire barrier penetration seals and failure to
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adequately establish fire barrier inspection procedures. As part of the licensee's corrective action, inspection procedures were revised to provide better guidance and requirements for barrier inspections. The inspectors walked down several fire areas with the fire protection system engineer and reviewed procedure PT-105.1.48, which was completed on July 16.
The inspections performed by the licensee identified nine penetrations which did not meet the acceptance criteria specified in the procedure.
Six penetrations were found on the charging pump cubical south wall.
Each penetration used Dow Corning silicon foam as the barrier material.
The foam depth did not meet the eight-inch acceptance criteria.
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each penetration, a work request and DR was initiated.
A fire watch was established until repairs were made. The inspectors noted improvements in performing the inspections.
Station drawings were used to complete the inspections and the number and detail of discrepancies that were identified were indicative of more thorough inspections.
Inspections of fire penetrations between Unit 1 mechanical equipment
room and normal switchgear room were also observed. These inspections
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were being performed independent of the PT to check the integrity of large block out type fire barriers (barriers where cable trays go through fire walls).
The inspections fulfilled a commitment in response i
to Special Report 92-804 that was submitted to the NRC on December 22, 1992 because of deficient barriers.
As part of the licensee's IPE corrective actions, fire barriers were removed in the QS pump house to implement work activities associated with a DCP. When marinite boards were removed from the penetrations, gaps were discovered in the fire barrier foam material. The gaps extended the entire barrier length. As a result, the licensee opened CTS item 02-93-2101-001.
The CTS committed to inspect at least one
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similar barrior to see if a generic problem existed.
On July 29, the
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NRC inspectars observed an inspection of a large block out type fire barrier between the Unit I cable spreading room and turbine building.
When the marinite board covering the foam barrier was removed, gaps approximately one inch wide were noted the entire length at the top and
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bottom of the barrier.
The gaps extended all the way through the
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barrier.
In addition, large voids were found in the foam material.
- These types of barriers are generally not inspected because of the marinite board covering the penetration. On that same day, the inspectors identified a similar problem with a Unit 2 fire penetration barrier.
The marinite board had holes through it which exposed a small portion of the Dow Corning foam.
By viewing the foam seal through these small holes, it was evident that gaps existed in the silicone foam
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material similar to those described above.
Based on the sample inspection of barriers of this type, it was evident
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that a generic problem existed. The licensee developed a list of all block out type fire penetrations at the station and established an hourly fire watch of these areas.
Nineteen barriers were identified.
As of July 29, six of the penetrations had been inspected with five
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showing gaps all the way through the fire walls.
The inspections and repair represented an extensive effort.
Scaffolding has to be erected for most of the barriers and removal of the marinite board is destructive.
Based on several of these barriers being inoperable for greater than seven days, a special report was sent to NRC in accordance with UFSAR Technical Requirement 16.2.1.3.
On August 2, the inspectors verified by reviewing fire watch assignment sheets that hourly fire watch requirements were met for the large block out barriers and the inoperable penetrations identified during PT i
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105.1.48.
Based on the inspectors review, no instances were. identified where fire watches were missed. These violations will remain open until the licensee completes all of the action items necessary for closure.
No violations or deviations were identified.
7.
Exit (30703)
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The inspection scope and findings were summarized on August 25, 1993, with 150se persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the results listed in the summary section. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
8.
Acronyms and Initialisms
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AFW Auxiliary Feedwater CDA Containment Depressurization Actuation
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CR0 Control Room Operator
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CTS Commitment Tracking System DC Direct Current
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DCP Design Change Package DR Deviation Report ECCS Emergency Core Cooling System ECST Emergency Condensate Storage Tank
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EDG Emergency Diesel Generator
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FCV Flow Control Valve
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GPM Gallons Per Minute
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HCV Hydraulic Control Valve
HHSI High-Head Safety Injection l
I&C Instrumentation and Control
IPE Individual Plant Examination
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IR
Inspection Report
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Inservice Testing
LC0
Limiting Condition for Operation
MS
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NRC
Nuclear Regulatory Commission
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Operating Event Report
PG
Primary Grade
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Preventive Maintenance
Periodic Test
Quality Assurance
Quality Control
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QS
Quench Spray
Reliability-Centered Maintenance
Safety Injection
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TS
Technical Specification
TV
Trip Valve
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Updated Final Safety Analysis Report
Work Order
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