IR 05000338/1992029

Insp Repts 50-338/92-29 & 50-339/92-29 on 921122-1219.No Violations Noted.Major Areas Inspected:Operations,Maint, Minor Mods,Surveillances & Action on Previous Insp Findings

ML20127K157
Person / Time
Site:	North Anna
Issue date:	01/13/1993
From:	Lesser M, Sinkule M, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20127K146	List: IR 05000338/1992029 ML20127K143
References
50-338-92-29, 50-339-92-29, NUDOCS 9301260058
Download: ML20127K157 (14)

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%**..+p Report Nos.: 50-338/92-29 and 50 339/92 29 R

Licensee: Virginia Electric & Power Company 5000 Dominion Boulevard .

Glen Allen, VA 23060 l

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Docket Nos.: 50-338 and 50-339 License Nos.: NPf-4 and NPf-7 r facility Name: North Anna 1 and 2 Inspection Conducted: November 22 - December 19, 1992

IC Le De esidnbnspector ~D e i ed (E R,> fb ~N &laylor,RIfde_ntinspector Eh Ub __ ~Date signef Approved by: [ f,

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i. C$liikW, branch C ief ~Date $lgnef Division of Reactor Projects SUMMARY Scope:

This routine inspection by the resident inspectors involved the following areas: operations, maintenance, minor modifications, surveillances,'and action on previous inspection findings. Inspections of licensee backshift activities were conducted on the following days: November 25 and December 6, 8 and 17, 199 Results:

In the area of maintenance / surveillance, the licensee identified that nuclear instrument testing has not been performed in accordance with technical saecifications. The' licensee's corrective action involves testing the channel w111e it is tripped at one point and bypassed during another point. In that the licensee may be testing more functions than the minimum required by the technical specification, this may conflict with NRC policy regarding the use of limiting condition for operation action statements for testing and maintenance during reactor operation. Adequacy of this methodology remains under review and was identified as an unresolved-item (para 6,c),

in the area of maintenance, the reliability centered maintenance program was-reviewed. Controls to improve the implementation process were recently ,

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instituted and the program appears to be getting back on track (para 4.a).

9301260058 930113 PDR ADDCK 05009330 0 PDR-

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In the area of maintenance / surveillance, the licensee has replaced 77 of 83 l Klockner Moeller 480 volt circuit breakers due to a Part 21 concern. The replacement progrtm was evaluated as a strength (para 7.b).

l j in the area of engineering / technical support, a system engineer's alert review of motor operated valve test data identified that the results had not been i adequately evaluated, The review was not programmatically required and was a  !

good example of an engineer's efforts to maintain awareness of system status.

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further detailed evaluation was performed and properly documented (para 4.c).

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I REPORT DETA1 . Persons Contacted Licensee Employees

• Bowling, Manager, Nuclear Licensing and Programs

• Crist, Supervisor, Station Procedures 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, St: tion 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 Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personne NRC Resident Inspectors

• Lesser, Senior Resident Inspector

• D. Taylor, Resident inspector

• S. Lee, Senior Materials Engineer-

' Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap . Plant Status Unit I continued to operate in end-of-life coastdown ending the inspection period at 45% powe Unit 2 operated the entire inspection period at 100% powe . Operational Safety Verification (71707)

The inspectors conducted frequent visits to the control room to verify 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 TSs and to maintain awareness of the overall operation of the facilit 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 was applied, Mis-labelled Valves _

On November 23, the licensee identified that the isolation valves on the two fuel oil supply lines (1-EG-303 and 306) to the IJ EDG Day Tank were reverse labelle The condition was determined when operators were unable to drain the supply line from the IJA fuel oil transfer pump after the tagout was supposed to have isolated the lin The day tank is supplied by two redundant fuel oil transfer pumps (lJA and lJB) via redundant supply lines. The licensee had tagged out the IJA pump to install a discharge flow rate instrument. Due to the mislabelling, the IJA suction valve and the IJB pump supply line isolation valve were tagged, which unknowingly rendered the IJ EDG inoperabl Upon discovery, the licensee immediately cleared tags and restored the system to an operable status. The total time of inoperability was approximately 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> The inspectors verified that the lH EDG and other safety systems remained operable during the time frame, thus, the event occurred ~

within the TS allowable outage time. The inspectors additionally reviewed several past maintenance activities on the fuel oil system and the associated tagouts including the IJA pump replacement of May 1991 and the fuel oil storage tank cleanings in 1990. It was determined that the tagouts and valve alignments did not render the EDG or the fuel oil system inoperable. Over the next several days, the licensee performed flow testing to verify system configuration and no other problems were identifie The inspectors questioned the effectiveness of the licensee's configuration management program since the fuel oil system had been recently walked down and re-labelled. The supply lines cannot be traced directly from the fuel oil transfer pumps because portions of it are buried, however, station yard drawing Il715-FB-4A shows the piping layout. The licensee's re-labelling program (configuration management) does not require review of station yard drawings for buried piping if the component has previously been labelled and has a valve lineup procedure associated with i . _ _ - _ _ _ - _ _ _ _ _ _ _ _ - _ _ - -

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3 Use of TS 3.6. On December 9, the licensee identified a concern involving relay -

testing where automtic start of an outside recirculation spray pump and its associated casing cooling pump are simultaneously rendered inoperable for less than one minute. TS 3.6.2.2 does not specifically address this combination of inoperability and,-

therefore, the licensee considered that TS 3.0.3 should apply-during this portion of the test. The licensee pointed out that the safety function of the system is maintained by the opposite *

train recirculation and casing cooling pumps.- However, the casing cooling pump provides NPSH for the outside recirculation spray pump and, as such, is a. supporting componen The train is inoperable with either of the pumps non-functional. The licensee-concluded that the TS is poorly worded. The TS.LCO, in part,-

requires two outside recirculation spray pumps and two casing cooling pumps be operable. It provides an action statement if either a recirculation spray pump or a casing cooling pump is inoperable, rather than an action statement for an inoperable subsystem or train - both pumps simultaneously inoperabl The licensee intends to submit an LER for the concer The relay testing will continue as before and the licensee will voluntarily _

enter TS 3.0.3 during that period. The licensee will also submit '

a TS amendment request in a timely manner to clarify the requiremen The inspectors reviewed the NRC Inspection ManuL1 Part 9900 on the subject of voluntarily entering TS 3.0.3. The inspectors also discussed the issue with the NRR project manager and regional--

management, and determined the licensee's plans to be-acceptable.- Turbine Control System On December 17, the Unit 1 main turbine control system shifted from " operator automatic" to " turbine manual-impulse-in" without operator action. About 2: hours later, the operators noted a 10 MW drop in load. The operators took action.to control any-further load decrease and after stabilizing, shifted the_ turbine control system to " manual-impulse-out" control . At that time, an additional operator was assigned to the control. board-until the cause for the turbine control system response could be determine A short time later, the control systed again shifted back to

" impulse-in" without operator action. The operators thifted back to " impulse-out", but within a few minutes, the control system shifted back to " impulse-in". fhe operators continued to closely monitor the turbine control system while the malfunction was being evaluate The instrument shop's aiuation identified two potential _ control cards which, if failed, could affect the turbine control system in-the manner described. One of thi. control cards was replaced and

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4 the turbine control system returned to " impulse-out". The system remained in " impulse-out" for the remainder of the night with an additional CR0 assigned to the control board. On December 18, the tutbine was returned to " operator automatic" and the additional operator secured. The inspectors considered the licensee's action to provide for additional licensed operator monitoring of the turbine control system to be conservative and appropriat No violations or deviations were identifie . Maintenance Observation (62703)

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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, 4 Reliability Centered Maintenance The inspectors met with licensee representatives to review the development and implementation status of the RCM program. The program is described in Corporate Department Administrative Procedure 2, Preventive Maintenance Upgrade Program. The purpose of the program is to evaluate PH requirements based upon component functional importance, historical reliability and economic return with objectives of reducing system unavailability and corrective maintenance, and prioritizing maintenance resources. The licensee has been developing the RCM program for a few years, however, only recently established improved controls to prioritize and implement maintenance recommendation _

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RCM evaluations are first performed on each plant system of interest. Components within a system are then categorized according to relative significance in achieving RCH objective Failure modes and effects are analyzed. Maintenance histories, vendor data and several other sources are reviewed to determine component reliability and adequacy of PM requirements. The evaluation and recommendations are documented in the Maintenance Based Summary Inde Recommendations for PM changes are then prioritized to assure that those having the most immediate effect will be implemented firs The implementation process establishes the method by which the recommendation is implemented, i.e., via a procedure change, frequency change, engineering task, etc. The implementation process status is tracked through completion. The inspectors determined that only two systems (Charging and Rod Control) had all of the Priority 1 recommendations implemented. The evaluations of severai other systems such as AFW, SW and EDG have been completed since mid-1991 but the recommendations have not been implemented. The licensee attributed this to lack of a prioritization and implementation plan when the evaluations were

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complete Following development of the plan, the more recently completed systems were moved directly through to implementatio The licensee's goals are to complete implementation of the Priority 1 recommendations by June 199 The licensee discussed several examples of the more significant RCH recommendations. These include:

e increased reliance on motor / pump oil sampling rather than scheduled oil changes e reduced frequencies of diesel engine teardowns e reduced frequencies of manual valve lubrications e improved PM on heat tracing to reduce failures Additionally, the licensee intends to rely more heavily on thermography scanning of equipment instead of teardowns, Bottled Air System Maintenance On December 10, 1992, the inspectors witnessed maintenance on the control room bottled air system per WR 850610 and procedure 0-MCM-1006-01, Repair of Safety Related Piping and Component Bolted Flange Joints. The maintenance was being performed because of an air leak on an inline orifice. The flange connection was unbolted, inspected and a new gasket installed. The inspectors verified that the appropriate TS action statement was entered and that requirements and signoffs were met. The maintenance was completed and the system returned to service the same day. No problems were identifie Charging System Valve Maintenance On December 11, the inspectors observed troubleshooting of 02-CH MOV-2286A, charging pump discharge valve for the Unit 2 1A charging pump. The troubleshooting was in response to DR 2094, dated November 18, which documented that the MOV was returned to service without evaluation of high motor current in accordance with EWR 92-14 The EWR requires an engineering evaluation for currents 20% greater than nameplate. The nameplate motor current was 2.8 amps. The actual closing current was 4.0 - 4.5 amps and opening was 3.7 - 3.9 amps. The engineer did not perform the evaluation for 02-CH-MOV-2286A because an evaluation done a year earlier was noted to have approximately the same currents. The DR was written because more stringent requirements were in effect for evaluating high motor currents. Further engineering analysis is required for motors with operating currents greater than 20% of nameplat I

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The analysis for 02-CH-MOV-2286A included troubleshooting which was performed per WR 815362 using " skill of the craft". The valve was cycled by hand to identify any binding, followed by running the motor uncoupled from the valve actuator to measure current The current drawn by the motor in both the open and closed directions was similar to the opening current when the motor was coupled to the actuator (3.7 - 3.9 amps). Per a discussion with the maintenance engineer, these values were expected. The additional current for closing the valve with the motor coupled to the actuator was attributed to overcoming system pressur Following testing, the maintenance engineer submitted an EWR addendum for Design Engineering to evaluate the existing current against the motor temperature curves to ensure that the life of the motor will not be impaired by continued operatio The inspectors noted that the DR which documented the high currents was initiated because of a system engineer's independent review of maintenance test data. The inspectors considered this review, which is not required of system engineers, to be a good example of a system engineer maintaining awareness of relevant system changes and status. The evaluation for the valve motor demonstrated the motor to be operable for its design lif No violations or deviations were identifie . Minor Modifications (37828)

70% Project Review, Unit 2, DC 89-41-2 On November 23, the inspectors attended the 70% project review meeting for DC 89-41-2, RTD Bypass Line Elimination Project - Unit 2. The meeting had been previously scheduled, but was canceled due to poor attendance and a lack of comments. The inspectors noted that this meeting was very brief with several in attendance unprepared to ask questions or comment on the package. The inspectors discussed the apparent lack of preparation for the meeting with the project enginee The project engineer stated that he did not expect a significant number of comments because of the similarities between this DC and the Unit- 1 DC. The Unit 1 DC is scheduled for iinplementation starting January 1993, and has already gone through the DC approval process. The inspectors considered the meeting to be a poor example of implementing VPAP-301, Design Change Process, for a 70% Project Review. VPAP-301 requires a project review meeting at the station after issuance of a 70%

draft DCP. The purposes of the meeting are to: 1) review the design change; 2) obtain input from the project team; 3) discuss any of the station's concerns and any proposed resolutions; and 4) discuss station responsibilities for installation, operation, and maintenanc No violations or deviations were identifie .

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6. 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 resolve RCP Bus UF Test On November 24, the inspectors witnessed UF protection channel functional testing of the Unit 2 RCP buses. The licensee used procedure 2-PT-33.10(11)(12), Reactor Trip System Functional Test for RCP 2A(B)(C) Underfrequency. There is one UF relay for each of the three RCP buses and the tests verify that each relay activates one at a time when a test signal is applied. The test was thorough and adequately verified operability including alarm and trip functions. The inspectors noted good communication between the control room and the instrument racks as headset phones were used. Also, good self-checking and verification techniques were observed, Reactor Trip Breaker and Solid State Protection Testing On December 17, the inspectors witnessed the licensee perform 2-PT-36.lA, Reactor Protection and ESF Logic Train A. The inspectors verified that the procedure requires the reactor trip bypass breaker to be tripped with the local manual shunt trip prior to placing it in service as required by TS 3.3. The procedure was annotated to advise the Shift Supervisor of equipment, such as the 2H EDG and SW pump 2-SW-P-1A, which would be rendered inoperable during the test. The test was well controlled by a technician in the control room, who used headsets to communicate with technicians at the instrument rack Power Range Nuclear Instrument Testing On December 3, the licensee identified a potential violation of TSs involving surveillance testing of the PRNI. TS 3.3. requires a monthly channel functional test of each instrumen The licensee conducts the test using 1(2)-PT-30.2 which disconnects the detector input signals from the instrument drawer, rendering the channel inoperable (bypassed) without placing the channel into a tripped condition. This is done to check both the high setpoint (109%) and the low setpoint (25%) since the test circuit can only superimpose a test current onto an operable detector's output. The TS, in part, requires an inoperable channel to be placed in a tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, however, the licensee identified that the test has taken up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to complete without placing the channel in " trip."

The inspectors reviewed the licensee's corrective action which revised the test procedures. The channel is placed in a tripped

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condition by removal of the control power fuses prior to disconnecting the detector input signals. Later, the control power fuses are replaced to facilitate testingoof the power range drawer status indications and the trip bistables.: During this-portion of the test, the channel is bypassed without a channel *

tripped condition in effect. The procedure'has a caution statement to limit this part of the test to less than-1 hour in order to comply with TS Action The inspectors developed several concerns with the corrective action: The test is not being performed as described in the UFSAR section 7.2.2.2.1.6 which states:

The power range channels of the nuclear instrumentation system may be tested by superimposing a test signal on the actual detector signal being received by the channel at the time of testing. The output of the bistable is not placed in a tripped condition prior to -

testin Also, since the power range channel logic is two out of four, bypass of this reactor trip function is not required, it should be noted that a valid trip signal would cause the channel under test to trip at a lower actual- reactor power level. A reactor trip would occur when a second bistable trips.- No specific provision has been made in the channel test circuit for reducing the channel signal level below that signal being received from the ' nuclear instrumentation system detecto . The UFSAR also states that " bypassing" a channel for testing is only required for one-of-two protection logic-(source and intermediate range). This appears to be consistent with TS action 2.b. which would only allow ? bypassing" a PRNI channel :if it has previously been placed in " trip" due to-inoperability and a second PRNI channel needs to be surveillance tested; a rarely encountered condition. The licensee did not perform a 50.59 safety evaluation for this change in testing procedur . The licensee did not. consider the additional requirements of -

TS Action 2 with an inoperable channel. These require power to be restricted to s95% and PRNI setpoints to be reduced to 585% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or monitor Quadrant Power Tilt Ratio at least once per 12-hours with the moveable incore detector .

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The licensee believes they are required to test the low setpoint-_ -

by the TS (although it is blocked at 210% power) and can only do this completely by placing the channel- in bypass. The licensee indicated that quarterly channel calibration can only be done over the entire-range of the instrument by disconnecting the detector and that on-line testing would only be able to calibrate the-portion of the range above actual reactor powe The inspectors reviewed the monthly functional test procedure and determined that it checks more functions of the instrument tha the minimum required by TS, such as the P8 and P10 permissives and -

overpower rod stops. It is clear that the licensee's intent has been to develop a comprehensive test procedure. However, since the instrument is required to be out of service to_do some of these checks, the procedure appears to conflict with recent NRC policy contained in Generic Letter 91-18_and NRC_ Inspection Manual Part 9900, Maintenance - Voluntary Entry into Limiting Conditions for Operation Action Statements to Perform Preventive Maintenanc TSs permit entry-into LC0 action statements to perform surveillance testing for a number of reasons. One reason is that the time needed to-perform the _ task is usually only a small fraction of the allowable outage time specified in the action statement. In this case, however, the licensee is using up a significant portion of the allowable outage time, -1.e one hour to place the channel in trip and 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to reduce power. Another reason is that the benefit to safety derived from meeting surveillance requirements is considered to more than compensate for the risk to safety in having equipment out of service. It does not appear.in this case.that the licensee has sufficiently r weighed the expected improvement in equipment reliability against ,

the potential risk from operating the facility in an LCO action statement.- Pending1 further review and discussion with NRR of .the TS intent, this is identified as Unresolved Item 50-338/92-29-01:

PRNI Channel Testing in-Bypass.

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7. Action on Previous Inspection Items (92701, 92702) (Closed) Violation. 50-338, 339/91-10-01, Failure to Implement Procedures with four Examples This violation 1 involved a number of operator errors which were-caused primarily due to a lack of attention to detail and failure to employ self-checking techniques. The errors resulted in a loss of an emergency bus, a RCS level system being . rendered inoperable, an unplanned ESF actuation and an ECG _ incorrectly paralleled to-the grid during testin In_ addition to the cited examples, a declining trend in the area.of operator errors was noted:by the inspectors. .Following the issuance of this violation, two other violations (irs 50-338/91-26-01 and 50-338/92-03-01) were cited which also were partially attributable to operator erro The two latter violations have been closed by previous inspection _ _ _ _ _ __

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To address the specific examples cited by this violation, the licensee increased training and awareness in self-check techniques, issued an independent verification operations standard and obtained assistance from an outside organization to evaluate human performance concerns. In addition, and because of the-apparent trend, the licensee has aggressively pursued over the last year the causes for the human errors in order to reduce the number. The attention and resources committed to this issue by management has greatl,i increased the awareness of the operations and plant staff with rispect to attention-to-detail and self-check technique The following examples demonstrate some of management's accomplishments that have reduced the error rate since this concern was first raised:

• Revision of the self-check philosophy to make it less complex and more user friendly - The self-check method was reduced from a seven step process to the current four step procedure. Training on self-check methods was provided to the operations staf Self-check badges, buttons, posters and plaques are routinely worn by individuals and disseminated throughout the plan * Extensive QA witnessing and data collection of operator independent verification - The witnessing included tagging and procedural step verifications. Over 39,000 independent verification activities have been witnessed. The data and observations are trended and presented to management. The observations have helped to identify areas which have in the past been shown to be precursors to errors. For example, QA identified on several occasions that operators assigned to perform a'tagout or procedure step would be interrupted or otherwise distracted.from the task. Management implemented corrective action to address these-distraction * Aggressive approach toward tracking, trending and reporting l of errors - All tagging and procedural performance errors,

! regardless of significance,- are reported per the DR-proces Errors are divided into severity levels with.the highest level resulting in a TS violation. The error rate and trends are subsequently reported to managemen * An industry-recognized human performance expert has made two site visits to evaluate the methodology for collection of personnel error data and to recommend enhancements for human -

performance improvemen * HPES evaluation of errors-deemed necessary by managemen . -

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e Improvement in procedures as exemplified by the ability to electronically revise procedures and reduce the backlog of PAR Overall, the inspectors considered that management initiatives taken as a result of an apparent trend in error rate have had positive results, (Closed) Inspector followup Item 50-338/92-14-01: Klockner Moeller Breaker Failures The licensee reported the defective polymer-fiber spring arm in the breaker operating mechanism in accordance with 10 CFR 21 on July 1,1992. The licensee implemented a compensatory program to visually check for tripped breakers on a daily basis until the breakers were replaced. A replacement program was also developed which prioritized changeout of 83 circuit breakers. To date, all non-outage circuit breakers have been repirced. Six replacements will be done during refueling outages. The replacements were accomplished under strict controls using a prccedure specifically developed for the issue. The procedure required bench tests of replacement breakers which included insulation resistance, resistance readings across contacts, short time overturrent response time tests and instantaneous tests. All replacements were witnessed by QC and key steps were independently verifie In addition, since load testing would not be practical in all cases with the unit operating, all electrical connections were video taped for further verificatio The licensee performed a root cause analysis which determined that the cracks were stress cycle related due to an inadequate desig This conclusion conflicted with a failure report received from the manufacturer which concluded that a chloro-flouro carbon chemical cleanser or lubricant must have been used and contributed to stress corrosion crackin Since the breakers are molded-case, the licensee performs no such intrusive maintenanc While the root cause analysis remains inconclusive, the inspectors considered the licensee's corrective actions to be prompt, extensive and carefully coordinate . Exit (30703)

The inspection scope and findings were summarized on December 22, 1992, with those persons indicated in paragraph 1. The inspectors described the areas inspected and discussed in detail the inspection results listed below. Proprietary information is not contained in this repor Dissenting comments were not received from the license _ _ _ _

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Item Number . Description anA Reference

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50 338/92-29-01 (URI) Power Range Channel Testing in Bypass l (para 6.c) j Acronyms and initialisms AFW Auxiliary feedwater ^

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CFR Code of Federal Regulations CR0 Control Room Operator .

Design Change

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DC DCP Design Change Package DR Deviation Report ECCS Emergency Core Cooling System EDG Emergency Diesel Generator ESF Engineered Safety-feature EWR Engineering Work Request t

tiPES Iluman Performance Evaluation System

IR Inspection Report ,

LCO Limiting Condition for Operation.

i LER Licensee Event Report MOV Motor-Operated Valve

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NPSil Net Positive Suction Head l NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation PAR Procedure. Action-Request-PM Preventive Maintenance PT Periodic Test

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PRNI Power Range Nuclear Instrument QA Quality Assurance

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QC Quality Control

RCH Reliability-Centered Maintenance

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RCP Reactor Coolant Pump i RCS Reactor Coolant System

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RTD Resistance Temperature Detector SW Service Water p TS -Technical Specification UF - Underfrequency-

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UFSAR Updated Final Safety Analysis Report

URI Unresolved item

. VPAP Virginia Power-Administrative Procedure.

WR Work Request i

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