IR 05000280/1994033

Insp Repts 50-280/94-33 & 50-281/94-33 on 941211-950121.No Violations Noted.Major Areas Inspected:Plant Status, Operational Safety Verification & Maint Insp

ML18153B244
Person / Time
Site:	Surry
Issue date:	02/16/1995
From:	Branch M, Kern M, Moore L, Tingen S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML18153B243	List: IR 05000280/1994033 ML18153B242
References
50-280-94-33, 50-281-94-33, NUDOCS 9503080268
Download: ML18153B244 (27)

Text

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Report Nos. :

Licensee:

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 50-280/94-33 and 50-281/94-33 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 1 and 2 Inspection Conducted:

December 11, 1994 through January 21, 1995 Inspectors:

Approved by:

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G.2~Chief Division of Reactor Projects SUMMARY Scope:

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Dae igned 2-6~/qC:-

Date Sfgned

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Da t~ S~gned 1,.-,, 9:,

Date S gned This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance and surveillance inspections, plant support, safety assessment and quality verification, and action on previous inspection item Inspections of backshift, and weekend activities were conducted on December 12, 13, 16, 19, 21, 27 and 29, 1994, and January 4, 5, 6, 8, 9, 10, 12, 14, 15, and 17, 199 PDR ADOCK 05000280 G

PDR

• Results:

Operations:

The Station Nuclear Safety and Operating Committee's startup assessment following the Unit 1 steam generator chemical cleaning outage (SGCC) was properly focused on safety. Difficulties regarding reactor coolant system leakage and rod control system problems were methodically evaluated and resolve Command and control within the control room were good and procedures were performed as written (paragraph 3.1).

The material condition of heat trace circuits for boric.acid systems and cold weather protection equipment was goo The system engineer demonstrated detailed knowledge regarding the design of heat trace circuits and initiated procedure revisions to further improve the quality of preventative maintenance (paragraph 3.3).

Automation of the unit narrative control room logs and the station night orders was a positive initiative which has been effectively implemente Operators continued to be alert to control room indications and were not distracted by ready access to the station network from the control room terminal During the recent Unit 1 SGCC outage, network access to night orders enhanced the timely communication of management direction regarding work schedule and departmental coordination throughout the station (paragraph 3.4).

Infrequently conducted or complex tests or evolutions briefings conducted by senior management significantly heightened the operators' sensitivity to the safe operation of the unit (paragraph 3.6).

Maintenance :

The SGCC was effective in removing the scale buildup from the Unit 1 steam generator tube support plates. Quality assurance oversight was detailed and indicated a good sensitivity to foreign material exclusion control Licensee follow-through on lessons learned from the Unit 2 SGCC outage, including ventilation filter evaluation was good (paragraph 4.1).

An unresolved item was identified and is associated with issues related to the Unit 1 turbine driven auxiliary feedwater pump failure (paragraph 4.2).

A maintenance audit performed by the licensee was thorough and identified two findings that were associated with non-compliance of station administrative procedures (paragraph 4.3).

Corrective actions have resulted in improved operation of the 555 ton mechanical chillers in that fewer entries into Technical Specification action statements due to chiller trips have occurred (paragraph 4.4).

Maintenance and engineering personnel coordinated closely with vendor personnel to evaluate and correct excessive reactor coolant pump C seal leakoff following seal replacement (paragraph 4.5).

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The licensee properly reviewed Information Notice 91-13 and as a result of their review implemented emergency diesel generator testing that exceeded Technical Specification surveillance requirements (paragraph 4.6).

The licensee implemented good corrective action in response to reactor trips attributed to single relay failures (paragraph 4.7).

The licensee has continued to effectively manage the number of open cause determination evaluations (paragraph 4.7).

Improvements were implemented to prevent the intrusion of ground water into areas that contain safety related equipment and the licensee has continued to improve station appearance through a number of reclamation projects (paragraph 4.10).

The corrective actions implemented to reduce pressurizer safety valve seat leakage have resulted in significant improvement in operation of the units (paragraph 4.11).

Plant Support:

Significant restoration and preservation activities were completed in the lower level of the auxiliary buildin Contaminated areas within the auxiliary building were promptly restored to clean standards following completion of preservation activities (paragraph 5).

The post trip review, following the Unit 1 January 8 reactor trip, was thorough in both causal analysis and system response assessmen Results of the post trip review were clearly communicated to station management and thoroughly assessed prior to restart authorization (paragraph 6).

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REPORT DETAILS PERSONS CONTACTED Licensee Employees

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• * * * * * *A. * * * * * * * Benthall, Supervisor, Licensing Blake, Jr., Superintendent of Nuclear Site Services Blount, Superintendent of Maintenance Boehling, Maintenance Bryant, Licensing Christian, Station Manager Costello, Station Coordinator, Emergency Preparedness Emmons, Maintenance Erickson, Superintendent of Radiation Protection Farinholt, Maintenance Fletcher, Engineering Friedman, Superintendent of Nuclear Training Garber, Licensing Hayes, Supervisor, Quality Assurance Hayes, Superintendent of Administrative Services Keagy, Nuclear Materials Llewellyn, Superintendent, Nuclear Training Luffman, Superintendent, Security McCarthy, Assistant Station Manager Miles, Supervisor, Quality Assurance Miller, Nuclear Licensing Price, Assistant Station Manager Sarver, Superintendent of Operations Saunders, Vice President, Nuclear Operations Sloane, Superintendent of Outage a,,.:; Planning Smith, Site Quality Assurance Manager Sommers, Supervisor, Licensing, Corporate Sowers, Superintendent of Engineering Stanley, Supervisor, Station Procedures Swientoniewski, Supervisor, Station Nuclear Safety Woodzell, Nuclear Training Wooten, Nuclear Licensing & Programs Other licensee employees contacted included plant managers and supervisors, operators, engineers, technicians, mechanics, security force members, and office personne NRC Personnel

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M. Branch, Senior Resident Inspector D. Kern, Resident Inspector S. Tingen, Resident Inspector

• Attended Exit Interview

• Acronyms and initialisms used throughout this report are listed in the last paragrap.

PLANT STATUS Unit 1 was in cold shutdown for SGC All three SGs were chemically cleaned and the C RCP seal was replaced during the Unit 1 outag Unit 1 reactor startup began on December 2 The licensee experienced difficulties in performing required post startup testing of the TDAFW The unit was placed on the distribution grid on December 25 after TDAFWP was demonstrated operabl Unit 1 achieved 100 percent power on December 2 On December 29, a Unit 1 turbine runback occurred in response to a failed IRP Reactor power stabilized at 64 percen Operators promptly restored Unit 1 to full powe On January 8, the Unit 1 reactor tripped due to low SG levels following a main feedwater pump trip. Safety system responses to the unit trip were normal with the exception of TDAFW Unit 1 was restarted on January 14 and returned to 100 percent power on January 1 Unit 1 was at 100 percent at the close of the report perio Unit 2 was operating at 100% reactor power at the beginning of this report perio On January 10, an end-of-cycle coastdown was begun and at the close of the report period, the unit was at 90 percent powe.

OPERATIONAL SAFETY VERIFICATION (71707, 71714, 42700)

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 complianc~ with TSs and to maintain overall facility operational awarenes Instrumentation and ECCS lineups were periodically reviewed from control room indication to assess operabilit 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.1 Unit 1 Startup Following SGCC Outage The inspectors attended the SNSOC review of the station startup assessment following the Unit 1 SGCC outage completio Each department presented a concise review of work status and readiness for restart. The action plan for remaining startup hold items, such as assessing the C RCP seal leakoff following the C RCP seal replacement, were presented and discussed in detai The inspectors concluded that SNSOC performed an effective startup assessment which was properly focused on safety.

• Operators began RCS heatup from cold shutdown solid plant conditions on December 2 The inspectors observed control room and various in-plant activities during RCS heatup and reactor startup. Operators closely trended both RCS and PZR heatup rates, maintaining both well below the TS limits. Administrative controls were properly established when opening MSTV bypass valves for secondary plant heatu Command and control within the control room were good and procedures were performed as writte After achieving normal operating temperature, the licensee experienced difficulties with the rod control system and excess RCS leakage into the POT Both issues were methodically evaluated and satisfactorily resolved. Criticality was achieved on December 2 The inspectors monitored main turbine startup to 1800 rpm and turbine trip tests. Operators coordinated effectively to minimize the time during which turbine speed was in the critical vibration rang Pertinent plant parameters

including SG levels, reactor power, feedwater header pressure, and turbine vibration were closely monitore The TDAFWP tripped on overspeed while performing the component operability verification test on December 24 and 25, 199 The TDAFWP was successfully demonstrated operable at 2:30 pm on December 2 Power ascension was initiated and 100 percent power was achieved on December 2.2 Licensee 10 CFR 50.72 Report, Unit 1 Trip On January 8, the licensee made a non-emergency four-hour 10 CFR 50.72 report due to Unit 1 automatically tripping because of low-low SG level. This report was made within the time requirements of 10 CFR 50.7 A lube oil leak developed on the B MFW pump inboard motor bearing lube oil line which resulted in the B MFW pump automatically tripping on low lube oil pressur When the B MFW pump low lube oil pressure annunciator alarmed in the control room, operators immediately initiated a unit ramp dow At 74 percent power the unit automatically tripped due to low-low SG leve The inspectors reported to the site following the Unit 1 reactor trip and verified that the motor driven auxiliary feedwater pumps automatically started and SG blowdown isolated as designe The TDAFWP automatically started but tripped on overspeed (paragraph 4.2).

The unit cooled down following the trip and at 532 degrees F the MSTVs were shut and temperature stabilized at approximately 532 degrees Minimum RCS pressure following the trip was 1800 psig, minimum pressurizer level was 8 percent and minimum level in the SGs was approximately 17 percen SI initiation was not required and did not occur nor did SG or RCS safety valves or PORVs ope Following the reactor trip, operators were not able to immediately verify that rod K2 fully inserted because the !RPI for the rod was inoperable. This condition existed prior to the trip and the inoperable !RPI for

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rod K2 was repaired prior to restarting the unit. After the !RPI for rod K2 was repaired, it indicated that the rod was fully inserte.3 Cold Weather Preparations (71714)

The inspectors reviewed the licensee freeze protection and heat trace program to determine whether the licensee had established adequate measures to address the effects of cold weathe Procedures O-OSP-ZZ-001, Cold Weather Preparation, revision 1 and O-EPM-1303-01, Freeze Protection Inspection, revision 3, are performed monthly from October through March to confirm that exposed systems are properly protected from freezin A QA audit identified that one of the monthly procedures had not been scheduled to be performed in Octobe This finding was communicated to the appropriate personnel in a timely manner and the surveillance was completed within the prescribed mont The inspectors reviewed the results of the latest two months'

surveillance and maintenance procedures and concluded that the freeze protection and heat trace systems (with one exception) were being properly maintaine Work requests with appropriate priorities were assigned to all discrepancies which had been identified during the monthly surveillance The inspectors and system engineer reviewed the status of approximately thirty WR tags and danger tags which were found attached to heat trace circuitry. Several WR and danger tags were not cleared after the WO had been complete The inspectors discussed this observation with the Maintenance and Operations Superintendent The licensee initiated correctiv~

actions to focus more attention on clearing tags following WO completio The inspectors determined that the immediate and fo 11 ow-up corrective actions were adequate to verify WR tags anJ danger tags hung on equipment are curren The inspectors toured the station with the system engineer and physically inspected various heat trace circuits and outside pipin The general condition of heat trace circuits, space heaters, heat lamps, and insulation of exterior piping and instrument lines was goo For those areas inspected, the inspectors verified that temperatures were within the range specified by station procedure The licensee upgraded the heat tracing circuits on piping at the high level intake structure late in 199 The inspectors verified that the circuits had been returned to operation following maintenance and that insulation had been properly reinstalle The system engineer demonstrated detailed knowledge regarding the design and current condition of heat trace circuits.

The inspectors noted that the control room annunciator for the low level intake structure heat trace system trouble alarm was

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energize The system engineer initiated an equipment investigation sheet on this circuit, determined that the control room annunciator was malfunctioning, and submitted a work request to fix the annunciato The inspectors reviewed OC-21, Severe Weather Checklist, dated November 1, 1994, and determined that the freezing concerns identified at the low level intake structure in 1994 were properly addresse Puring plant tours, the inspectors observed heat lamps had been temporarily added to supplement existing heat trace circuits, but, their power supplies were disconnecte In addition, the insulation enclosures were not properly secured around the level instrument The inspectors informed the SS who took prompt action to energize the heat lamps and properly reinstall the insulation enclosures. Additionally, the inspector discussed this observation with the Operations Superintendent who initiated appropriate action to ensure the condition of the insulation enclosure is verified when performing O-OSP-ZZ-00 The system engineer determined that the circuit which supplies power to the permanently installed heat traces for CST level instrumentation has five parallel heat trace elements/strip Parallel heat trace elements on a single circuit were not checke Therefore performing procedure O-EPM-1303-01 did not assure that the heat trace circuit installed in the CST level instrument enclosure was workin The system engineer initiated WR 34000 and subsequently determined that each CST level instrumentation heat trace elements/strips were operabl The temporary heat lamps were removed and the insulation was properly reinstalle In addition, the syst~m engineer initiated an engineering tracking commitment to review and revise statior procedures to ensure that each individual (parallel) heat trace element/strip is periodically verified to be operating properly. These actions were appropriate to assure adequate cold weather protection for the CST level instrument.4 Automated Control Room Logs and Station Night Orders In 1994, operations personnel began documenting the unit narrative log electronically using the station LAN instead of hand writing the logs on pape The inspectors observed control room log keeping practices throughout the year and observed several positive benefits resulting from electronic log keepin Electronic access to the unit narrative log via the station LAN provided personnel throughout the station with real time visibility into plant conditions and emerging problem Engineers, maintenance, and management personnel were frequently observed to make use of the electronic logs to enhance timely resolution of issues affecting station operatio In addition, the combined departmental station night orders were placed on the LA The inspectors observed that during the recent Unit 1 SGCC outage, LAN access to night orders enhanced the timely

communication of management direction regarding work schedule and departmental coordination throughout the statio Procedure OPAP-004, Logs and Operating Records, revision 4, provides excellent instructions regarding content, processing, and reviewing the electronic unit narrative lo Unit narrative logs have been detailed and have provided an accurate description of significant operational evolution The inspectors concluded that automating the unit narrative logs and the station night orders was a positive initiative which has been effectively implemente.5 Heatup/Cooldown Rates The inspectors reviewed the licensee's methods for monitoring plant heatup and cooldown rates for the RCS system and the PZ Plant heatup and cooldown procedures specify limits for RCS heatup and cooldown rates and require that RCS pressure and temperature be plotted on a plant curve figure every 25 degree F change in RCS temperature. Also, procedures require that the plant computer program for calculating RCS heatup or cooldown rate be initiated and monitore Plant heatup procedures do not specify limits for PZR heatup rate and it is not plotted. These procedures do specify RCS heatup limits which are less than PZR heatup limits. The plant cooldown procedure for hot shutdown to 345 degrees F specifies PZR cooldown rate limits but does not specify how to monitor the cooldown rat The procedures for cooldown from 345 degrees F to ambient do not specify limits for PZR cooldown rate but the procedures specify RCS cooldown rates which are less than PZR cooldown rate The procedure for collapsing a steam bubble and subsequent cooldown of the PZR does not specify PZR cooldown rate limits or require that the PZR cooldown rate be plotted or monitored on the plant compute The procedure for drawing a steam bubble in the PZR specifies pressurizer heatup rate limits but does not require that the PZR heatup rate be plotted or monitored on the plant compute During the Unit 1 heatup that occuired on December 20 through 24, the inspectors monitored RCS pressure and temperatures plots and verified compliance with TS heatup limits. After discussing the methods of monitoring plant heatup and cooldowns with the licensee, it was concluded that heatup/cooldown procedures warranted improvements; especially in the area of monitoring PZR heatups and cooldown During the Unit 1 heatup an STA was assigned to monitor heatup and cooldown rate At the end of the inspection period the licensee was initiating procedural changes and was planning to review previous PZR cooldown evolutions in order to verify that TS cooldown rates were not exceede.. *

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7 Unit 1 January 14 Startup On January 14, the inspectors witnessed the Unit 1 startu Evolutions monitored included taking the unit critical in accordance with l-OP-RX-006, Withdrawal of Control Banks to Critical Conditions, revision Prior to taking the unit critical, operators were briefed by the senior operations manager in accordance with VPAP-0108, Infrequently Conducted or Complex Tests or Evolutions, revision Operators performed the unit startup in a deliberate and controlled manne Procedures were followed and command and control were goo Topics discussed during the senior operations manager briefing included previous*

lessons learned, strict compliance with procedures and stopping the evolution if problems develo The inspectors concluded that the infrequently conducted or complex tests or evolutions briefing by senior management significantly heightened the operators'

sensitivity to safely operating the uni.7 Unit 1 Containment Walkdown On December 20, the inspectors walked down the Unit 1 containmen The overall condition of the containment was considered*goo Several ladders were not properly stowe This discrepancy along with other minor discrepancies was noted and recorded by the SS and provided to outage management for dispositio The inspectors noted the containment sump was clea.8 Biweekly ESF Inspections 3.8.1 Seismic Monitors On December 20, the inspectors walked down the two seismic monitors located in the Unit 1 containmen The monitors were enclosed in red poly in order to maintain the components free of contamination for calibration purpose.8.2 Walkdown of Unit 1 Hydrogen Recombiners The inspectors walked down the two hydrogen recombiners located in the Unit 1 containmen The inspectors ~erified that the vents on the hydrogen recombiners were not blocked and that the areas adjacent to the recombiners were clea Within the areas inspected, no violations or deviations were identifie MAINTENANCE AND SURVEILLANCE INSPECTIONS (62703, 61726)

During the reporting period, the inspectors reviewed the following maintenance/surveillance activities to assure compliance with the appropriate procedures.

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8 Unit 1 Steam Generator Chemical Cleaning In December, all three Unit 1 SGs were chemically cleaned to remove hard scale buildu Three separate cleaning stages were performed on each S Sludge lancing was then performed to remove residual materia The SGCC was performed by the same vendors that were used for the Unit 2 SGCC in June 199 The inspectors periodically observed the vendors operating the SGCC control station Personnel were knowledgeable and closely monitored parameters which were identified as critical to SGCC effectiveness (e.g., solution temperature, flow rate, pressure, pressure pulse rate, corrosion}.

The SGCC process resulted in a small amount of undesired corrosion to carbon steel and low alloy steel SG component A conservative corrosion limit of 0.004 inches wall thickness was establishe The inspectors discussed corrosion monitoring records and pressure pulsing with personnel at the SGCC control stations and determined that these parameters were properly established and controlle The licensee previously identified that responsibility for QA coverage of SG handhole and manway closure had not been clearly assigned during the Unit 2 SGCC project. The inspectors discussed QA coverage for the Unit 1 SGCC project with several QA inspectors and reviewed QA records for SG handhole and manway closur Inspection records were detailed and indicated a good sensitivity to FME controls in addition to closure bolt torquin FOSAR video inspections of the tubesheet section of each SG were performed prior to final closur The inspectors reviewed FOSAR video tapes with QA personne FOSAR inspection identified a six-inch long by 1/8-inch diameter wire in the C SG and seven small wires in the A S The wire pieces were removed prior to SG closure. Video quality was good and QA review of the tapes was detaile The amount of material removed from the Unit 1 SGs was fifteen to twenty percent more than that removed from Unit 2 SGs in June 199 Final estimates, in pounds, of the amount of material removed during the SGCC process is as follows:

SG A SG B SG C Copper 610 500 430 3990 3610 3890 Sludge 2411 2659 2530 The licensee determined the most likely source of the copper to be previously installed feedwater heaters which had copper/nickel tube New feedwater heaters containing titanium tubes were installed in Unit 1 in 199 Feedwater piping was the source of the iro The C SG exhibited the most severe oscillations prior to Unit 1 SGC The inspectors reviewed video tapes of the C SG tube support plates taken both prior to and after SGCC cleanin *

The post SGCC tapes indicated excellent scale buildup removal from the tube support plate Passages for normal hydrodynamic flow were restore No Unit 1 SG level oscillations have been observed since startu The inspectors concluded that the Unit 1 SGCC was effective in eliminating SG level oscillation Based on the degraded AVS filters during the Unit 2 SGCC, the licensee installed a temporary modification which bypassed the safety-related filters and redirected containment purge flow to the non safety-related Category II ventilation filter (l-VS-FL-14)

during the Unit 1 SGCC outage (see NRC Inspection Report No, 281/94-31).. Post outage sample results indicated that l-VS-FL-14 iodine removal efficiency declined by 3.3 percen Neither safety-related filters (l-VS-FL-3A, 38) were used to treat containment purge flow during the Unit 1 SGCC outag However, l-VS-FL-3B filter was used briefly to process refueling building exhaust during the Unit 1 SGCC outag The licensee demonstrated conservatism in obtaining a 1-VS-FL-3B filter sample following the Unit 1 SGCC outage completio Sample analysis for the 1-VS-FL-3B filter was not complete at the close of this inspection repor The inspectors observed that the licensee continued to follow through on lessons learned from the Unit 2 SGCC outag.2 Unit 1 TDAFWP Maintenance and Surveillance 4.2.1 Governor Repair/Replacement History Review The inspectors reviewed the maintenance activities associated with the Unit 1 TDAFWP during the SGCC outag Governor 228 was removed and governor 227 was installe The governor valve stem, governor valve stem packing,

.governor valve stem cushion spring and governor lever block were also replace Additi~~ally, the governor valve control 1inkage was rebuilt and adjuste TS 3.6.C and F require that the TDAFWP be operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of achieving criticality and prior to exceeding 10 percent reactor powe Unit 1 commenced a reactor startup on December 23, 199 While performing PMT on December 24 and 25, 1994, the TDAFWP started and tripped on overspee On subsequent TDAFWP test runs, the TSCS developed diverging oscillations and the TDAFWP tripped on overspee Governor 228 was reinstalled and the TDAFWP was reteste The TDAFWP tripped on overspee Subsequent reviews indicated that governor 228 exhibited excessive hunting in lieu of divergent oscillation The governor valve stem cushion spring that was replaced during the outage was reinstalled and the TSCS satisfactorily operated during testin [

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After additional testing, the governor high speed set point appeared to be drifting. Governor 227 was reinstalle During subsequent testing the TSCS developed diverging oscillations and the TDAFWP tripped on overspee A new governor valve stem cushion spring was installed and the TDAFWP was satisfactorily teste The TDAFWP TSCS was stable and diverging oscillations did not develo On December 27 the TDAFWP was again tested and satisfactorily operate The cause of the TSCS to not properly control turbine speed was not positively identifie On January 8, 1995, Unit 1 tripped due to problems associated with a MFW pump and low SG level The TDAFWP started on demand but tripped on overspeed after startin The inspectors reviewed the GETARS graph of steam flow to the TDAFW The graph indicated that the TDAFWP automatically started and tripped approximately 50 seconds late As the governor ramped to rated speed, diverging steam flow oscillations developed and the TDAFWP tripped on overspee ARCE team was assembled and an action plan which included additional testing was develope On the initial test run of the TDAFWP on January 10, TSCS divergent oscillations developed at high pump flow rates and the TDAFWP was manually tripped. The governor valve linkage was disassembled and some minor binding due to the lever block rubbing against the governor valve lever was identifie The governor valve lever block was reoriented which eliminated the rubbing. Also, it was identified that the governor control air pressure inlet port was not properly vented. A vented plug was subsequently installed in the governor housin The governor valve bonnet was also disassembled and inspected and no deficiencies were note On January 11 the TDAFWP was tested. This testing required operators to manually perturb the TSCS linkage at different TDAFWP flow rates and monitor system respons At 540 gpm diverging TSCS oscillations developed after perturbing the TSCS linkage and the TDAFWP tripped on overspee Governor 227 was re~oved and governor 228 which had been reworked at the vendor's Rocky Mount, North Carolina, service facility was installed. Diverging TSCS oscillations did not develop during subsequent testing. However, the TSCS did not properly control turbine speed and oscillations developed that would not dampen ou On January 12, the governor valve stem cushion spring was replaced and the TDAFWP teste At a discharge flow rate of 35 gpm operators manually perturbed the TSCS linkage and oscillations developed that would not dampen ou TSCS

• linkage oscillations were then manually induced at 250 gpm, 500 gpm and 700 gpm flow and satisfactorily dampened ou The TDAFWP was tested later on January 12 at a 35 gpm flow rate and manually induced TSCS oscillations satisfactorily dampen ou It could not be determined why on the initial test run at 35 gpm flow oscillations did not dampen out but did dampen out on subsequent test run The licensee installed the governor valve cushion spring that was installed during the January 8 overspeed trip in an attempt to duplicate the conditions that previously resulted in TSCS divergent oscillations or oscillations that would not dampen out. Divergent oscillations or oscillations that would not dampen out could not be duplicated during this testin The new governor valve cushion spring was reinstalled and the TDAFWP was tested on January 13 and 1 The results of the testing were satisfactory and on January 14, the Unit 1 TDAFWP was declared operabl The TDAFWP was again satisfactorily tested on January 15, 16 and 1 At the end of the inspection period, the TDAFWP was being tested on a weekly basi Because a possible common mode failure existed, the Unit 2 TDAFWP was declared inoperable on January The Unit 2 TDAFWP was satisfactorily tested on January 9 and declared operabl On January 15 the inspector witnessed the testing of Unit 2 TDAFW The purpose of this test was to perform TSCS testing in accordance with 2-0P-FW-0 This testing required that the TSCS disturbances be manually induced at various TDAFWP flow rate The results of this testing were satisfactor.2.2 Review of Work Controls Associated with Maintenance and Testing On December 24, governor 228 was installed in accordance with WO 301919 02 using skill of the craf On that same day the TDAFWP was started and tripped on overspee Following the trip the TSCS linkage was disassembled in accordance with WO 298288 0 During a subsequent test run it was noted that the governor valve spring seat was turning. Subsequent investigation identified that the set screw in the governor valve lever block had not been sufficiently tightened while reassembling the TSCS linkag Position of the valve spring seat determines the preload of the governor valve cushion spring. This preload is considered a critical element in the ability of the TSCS to properly control turbine spee The governor valve lever block set screw was tightened and the TDAFWP reteste During disassembly, mechanics noted that there was a quarter-inch misalignment between the connecting rod assembly and the governor servo clevis. This misalignment resulted from mechanics not properly aligning the linkage to the governor while installing the governo \\his condition was correcte On December 25, governor 228 was removed and governor 227 was installed in accordance with WO 301919 03 using skill of the craf The TSCS linkage was disassembled and reassembled a second time using WO 298288 Following this maintenance, the TDAFWP was tested and declared operabl After the January 8 reactor trip, the TSCS linkage was disassembled and inspected in accordance with WO 306913 0 During this maintenance on January 10, it was noted that the governor valve lever block was not installed in the optimum position. This resulted in some minor linkage binding due to the lever block rubbing against the governor valve leve The governor valve lever block was reoriented eliminating the rubbin The control air pressure inlet port on governor 227 was found not to be properly vente A solid plug was installed in the port in lieu of a plug with a hol The governor valve control air pressure inlet port is required to be vented to prevent governor speed drifts during fluctuations in room air temperature which changes pressure on the speed setting bellow Procedure O-MCM-1403-01, section 6.7, provides instructions for disassembling/assembling the TSCS linkag The inspectors reviewed section 6.7 and noted that the governor valve lever block was not addresse In reviewing WOs the inspectors also noted that on some occasions section 6.7 was used to dissemble/assemble TSCS linkage and on other occasions the same maintenance was performed by skill of the craft with maintenance engineering supervisio For example, WO 306913 01 was performed by skill of the craft and WO 298288 02 was performed in accordance with O-MCM-1403-01, section The inspectors reviewed TM 38-W971-00001, Woodward PG-PL Governor, revision The TM provides adjustment instructions for putting a new or overhauled governor in servic Procedure O-MCM-1403-01, section 6.12, Governor Post Maintenance and Operational Checks, implemented the TM requirements for putting a new or overhauled governor in servic The TM stated to induce hunting by opening the compensation needle valve or manually disturbing the governor speed setting. This is necessary to move the governor through its full output stroke to remove trapped

air in the hydraulic circuits. Procedure O-MCM-1403-01, section 6.12, required that the TDAFWP be started and to purge the governor of air only if excessive governor hunting is observe The procedure did not require that hunting be induced in order to move the governor through its full output stroke as specified in the T The TM stated to check the governor stability following adjustment of the compensation needle valve by manually disturbing the governo'r speed setting. The TM provided an acceptance criteria for compensation adjustment in that it is satisfactory when the governor returns to speed with only a slight over or undershoo The TM required that governor stability be verified by repeating the above two steps after bleeding air from the governor hydraulic circuit Procedure O-MCM-1403-01 also did not contain these vendor manual instruction Following governor 228 installation on January 11 the inspectors witnessed the licensee place the governor in servic The instructions for governor post maintenance and operation checks contained in O-MCM-1403-01, section 6.12, were not utilized on this occasio The governor vendor performed the post maintenance and operation checks and no procedure was utilized. The inspectors were informed that the governor vendor is always utilized to perform post maintenance and operation adjustments and check The performance of governor 228 following installation on January 11 was considered unacceptable and the TDAFWP was secure * The inspectors reviewed the statior. maintenance training pro~ram for the TDAFWP contained in JPM-0-51, Perform Maintenance to Terry Turbine, revision This area was considered specialized training and covered all TDAFWP component The standard for JPM-0-51 was O-MCM-1403-01 and personnel were tested on their knowledge of this procedur The inspectors concluded that if details such as installation of the governor valve lever block were not specifically addressed in O-MCM-1403-01 then personnel were not trained on the installation requirement The inspectors noted that the Terry turbine at the licensee's training facility did not contain the same TSCS as installed on the Unit 1 and 2 TDAFWP According to the licensee's training department, one maintenance engineer has attended a Woodward governor training cours The licensee is currently performing a RCE into issues involving the TDAFWP performanc Until this evaluation is fully completed, the variances between the station procedures and the TM guidance is identified as part of URI 50-280/94-33-01, Issues Relating to TDAFWP failur.2.3 RCE for the Unit 1 TDAFWP January 8 Failure On January 9, the licensee initiated a category 1 type RCE in accordance with procedure VPAP-1601, Corrective Action, revision The RCE team consisted of 12 members with various backgrounds and experienc The station Engineering Superintendent was the designated team leader and a root cause trained person from the corporate office was assigned to the tea The RCE team maintained a log book to document findings and proposed directio The inspectors closely followed the RCE team's effort The inspectors monitored the licensee's root cause process and performed periodic log book review The inspectors attended several RCE team meetings and held discussions with individual team member The RCE team identified several issues associated with the January 8 overspeed trip. Their review of steam and feed flow traces from GETARS data identified that the TDAFWP did not trip on the initial insurge of steam as it had done on previous trip The team determined that the TDAFWP operated for approximately 50 seconds prior to tripping on overspee This information in combination with discussions with the governor vendor focused their initial efforts at verifying the type of buffer spring in governor 227 that was installed at the time of the trip. The buffer spring was verified to be the type specified and the team then directed their focus to the linkag Measurements were taken and provided to a consultant to use in developing a model to evaluate control system stability. Although team members were assigned to perform the classical root cause processes such as component failure analysis, change analysis, event causal analysis, the team approach shifted to extensive testing as a method to identify the proble Through this testing the root cause process seemed to constantly shift focus between the linkage and the governor as the root caus The inspectors attended the SNSOC meeting on Saturday January 14, when the RCE team briefed the plant safety committee and presented their initial findings as to root caus The team described their investigation activities and the results of their extensive testing of the Unit 1 TDAFW Additionally, the team proposed a plan for additional testing of the Unit 1 and 2 TDAFW The team concluded that the most probable causal factors were

"Equipment Condition" and "Maintenance/Testing Practices."

The team's findings indicated that governor 227 which was in-place during the January 8 overspeed trip was suspect since diverging oscillations were only experienced with that governo Additionally, the team determined that

maintenance/testing was a causal factor because of inadequate vendor TM instructions and PMT instruction In this area the team concluded that the vendor had critical information to set-up the governor and linkage in the field and this information was not available to the Virginia Power personnel who performed governor replacement and linkage refurbishment during the December SGCC outag The SNSOC accepted the team's evaluation and recommended that operations review the information and than make an operability determination for the Unit 1 TDAFWP prior to unit restar The inspectors recognized that the licensee's RCE review was not complet The inspectors acknowledged the RCE teams'

preliminary finding However, the inspectors concluded that the weak maintenance and testing procedures were also a contributor since they did not contain vendor instructions that were availabl Based on review of the RCE team's log book and meeting with team members, the inspectors noted that the RCE efforts seemed to fall short of determining why governor 227 behaved as it did on January 8, and the possible impact of questionable program practices and equipment configuratio The specific inspectors concerns, described below, were discussed with SNSOC and the RCE tea The inspectors identified the following topics as part of URI 50-280/94-33-0l: Acceptability of controlling work activities using WOs in lieu of detailed SNSOC approved procedur.

Possible impact of Commercial Grade Dedication process used for governor procurement, repairs and testing conducted by the vendo. Storage requirements for the governor in the warehous.

Control of vendor information and vendor activitie.

Effectiveness of root cause proces The items identified in the URI above were discussed with the licensee and will be evaluated by the RCE tea The licensee's current schedule indicates that these issues will be evaluated by January 3 The inspectors will review the licensee's efforts and will conduct additional inspections to determine if generic weakness in the licensee's processes contributed to the January 8, on demand failure of the Unit 1 TDAFW Additionally, the inspectors will continue to follow the licensee's root cause efforts and augmented testing plan.

...

16 Review of QA Maintenance Audit The inspector reviewed Quality Assurance Maintenance Audit Report, S94-13, dated December 21, 199 The audit concluded that the Maintenance Program satisfied regulatory commitments and that the program was effectively implemente The audit identified the following two findings:

Maintenance department craft personnel did not have a clear understanding of what constitutes an acceptable work package and were not adhering to the administritive requirements which govern the accomplishment of work activities. The audit identified that a similar finding was identified during a 1992 audi Control Operation's activities were being performed utilizing work instructions to supplement procedure These supplemental work instructions were not reviewed and approved by SNSO Both findings were associated with non-compliance with station administrative procedures and a similar finding was noted during a previous audi These findings were entered into the QA tracking system for resolutio The inspectors concluded that the maintenance audit was thoroug Containment Partial Pressure TS Figure 3.8.1 requires that containment partial air pressure be maintained greater than or equal to 9.0 psi TS 3.8.D. specifies that if containment partial pressure is less that psia then containment air partial pressure must be restored to with~n acceptable limits within one-hour or be in at least hot shutdown within the next six-hour During the summer months, the 555-ton mechanical chillers were utilized to maintain containment temperature within TS limit NRC Inspection Report Nos. 50-280, 281/93-24 discussed operational problems associated with the 555-ton mechanical chillers tripping off line causing indicated containment partial pressure to fall below 9.0 psi In 1992 and 1993 there were 6 and 14 DRs, respectively, written to document that a one hour action statement was entered because containment partial air pressure was less than 9.0 psi In July 1993 a station task team was established to develop corrective actions that would improve chiller operation and reduce the frequency of TS action statement entries for restoring containment partial pressure. Corrective actions implemented as a result of the task team included establishing chiller condenser cleaning and winterization PMs, developing procedures for chiller evolutions, enhancing operator training modules, modifying chiller *

automatic trip logic, and enhancing pressure and temperature instrumentation utilized to monitor chiller operating parameter The inspectors reviewed DRs written in 1994 and noted that only two DRs were initiated due to indicated containment partial pressure falling below 9.0 psia after a chiller tripped off lin The inspectors discussed operation of the 555-ton mechanical chillers with the system engineer who had kept detailed records of trips that occurred in 1994. Although there were only two occasions where chiller trips resulted in entry into TS action statement 3.8.D.l.a, 39 chiller trips occurred in 199 The majority of these trips were attributed to low refrigerant charge and, once corrected, the chillers operated from July 14 to September 14, 1994 without any trip The inspectors concluded that corrective actions implemented have improved operation of the 555-ton mechanical chillers. The licensee has several open Level 1 projects to further investigate methods to improve chiller operatio *

Restoring Unit 1 C RCP The C RCP seal was replaced during the SGCC outage in response to degrading seal performance since July 199 The last portion of the C RCP seal replacement was coupling the pump to the moto RCP seal leakoff was excessive after the motor/pump coupling was completed on December 1 Physical inspection identified no seal abnormality. This indicated that the seal had not seated properly during the first couplin Based on discussions with the vendor, -

the coupling procedure was revised to reduce the amount of time the pump was off of its backseat prior to reestablishing seal flow; This reduced the amount of RCS backleakage and the potential for foreign material co11vaminatio The inspectors observed the RCP recoupling and noted close coordination between maintenance and operations personne The seal was reinstalled and the RCP was coupled successfull The inspectors concluded that the licensee effectively evaluated and corrected the excessive C RCP seal leakoff conditio RCP seal leakoff returned to normal following RCS pressurizatio The inspectors noted, however, that the torque sequence used when coupling the pump to the motor differed from that specified in work procedure VP-PMS-Pl.60, Reactor Coolant Pump Seal Inspection, revision The inspectors questioned why maintenance personnel used a different torque sequence without obtaining resolution from their superviso The mechanics informed the inspectors that they were torquing the coupling in accordance with the pre-job training which they had receive QA personnel initiated DR S-94-2303 to resolve the issu The licensee determined that the torque sequence used was correct and verified by the vendo Further, they_ concluded that a recent revision to the vendor procedure did not accurately state the torque sequence which the vendor

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intende The licensee initiated corrective action to ensure changes to vendor procedures are more clearly worde The importance of informing supervisors of work instruction discrepancies and obtaining resolution prior to continuing with a work task was emphasized at weekly quality maintenance team meetings with the craf The inspectors determined that the torque sequence used was acceptable and did not degrade the functionality of the RC Corrective action to address compliance with work instructions was adequat.6 No. 1 EOG Voltage Regulator Testing On December 26 the No. 1 EOG was tested in accordance with l-OPT-EG-001, Number 1 EOG Monthly Start Exercise Test, revision Step 6.4.2 required that prior to synchronizing the EOG to the emergency bus that the measured generator volts be adjusted from 120 volts to at least 140 volt The purpose of this step was to verify that the voltage regulator was properly operatin While performing step 6.4.2, the maximum voltage that could be obtained was 134 volts. This was the first time that this test method and acceptance criteria was used with the No. 1 EOG voltage regulato Because l-MPT-0700-01, EOG No. 1 Refueling Test, revision 0, performed on February 7, 1994, had demonstrated that the EOG was capable of supplying required reactive loads and the voltage regulator was able to properly respond to large voltage swings, _the EOG was considered operabl On January 5, the inspectors witnessed No. 1 EOG testing that was performed in accordance with l-OPT-EG-001, one time only change 95-00 This procedure had been revised to verify proper voltage regulator operability by performing reactive loading similar to l-MPT-0700-01 that was p~rformed on February 7, 199 The results of tht~ testing recqnfirmed that the voltage regulator, exciter and generator were properly operatin At the end of the inspection period, engineering was reviewing the best test method option for verifying voltage regulator operability on a monthly basi NRC Information Notice 91-13, Inadequate Testing of EDGs, dated March 4, 1991, discussed the need to demonstrate the capability of the EOG to carry its accident loa The licensee's review of this information notice resulted in modifying EOG testing to perform reactive loading on a refueling basi The licensee was also trying to further improve EOG testing by verifying proper operation of the voltage regulator on a monthly basi The inspectors concluded that the licensee properly reviewed Information Notice 91-13 and as a result of their review implemented testing that exceeded TS requirements.

4. 7 *Relay Replacement In 1993, the licensee performed a Level 1 engineering study that identified relays that would result in a reactor trip if a failure occurre Prior to performing this study, several reactor trips occurred due to single relay failure The relays identified by the study were replaced in both units and PMs were implemented to replace the relays every other refueling outag The inspectors noted that since July 1993 there were no reactor trips attributed to single relay failure The inspectors concluded that the licensee implemented good corrective action to prevent -reactor trips attributed to single relay failure When a reactor trip occurred due to a relay failure, the licensee would perform a COE to determine why the relay faile The licensee effectively managed the number of open CDE During this inspection period there was only one open CO.8 Review of WO Backlog The inspectors reviewed the status of the licensee's WO backlo On the day the review was performed there were 5889 open WO Included in this total were 2236 WOs to perform PM There were 3188 outage related WO and 2701 non-outage related WO Since a Unit 2 RFO is scheduled to start in February 1995, the inspectors reviewed the status of the Unit 2 outage and non-outage related WO Unit 2 had 3277 open WO were outage related and 824 were non-outage related. Approximately 2220 outage related WOs and 60 non-outage related WOs were scheduled to be worked during the upcoming RF The inspectors concluded that the licensee effectively managed the number of outage related WO Periodic and predictive maintenance successfully identified degraded and malfunctioning equipmen The licensee has effectively managed the number of non-outage WOs classified as corrective maintenance and deviatio.9 Station Technical Procedure Upgrade Program The inspectors reviewed the station TPUP status report dated January 3, 199 The station goal is to complete this program in 199 The report identified that there are 2438 procedures remaining to be upgraded in the next 2 year The inspectors discussed TPUP completion with the supervisor of procedures and were informed that at the current rate approximately 940 procedures are being updated a yea The TPUP is divided into electrical, mechanical, I&C, operations and other area The inspectors noted that at the current procedure upgrade rate all departments' procedures would be upgraded by the end of 1996 except for the I&C departmen Obtaining critical process loop data and scaling factors delayed

~ *.

upgrading l&C procedures when the program was initiated. The licensee has prioritized upgrading l&C procedures and has upgraded procedures that have the most effect on plant safet Approximately 501 l&C procedures have been completed and 961 procedures remain to be upgrade The licensee plans to review the scope of the I&C procedures that are scheduled to be upgraded and reevaluate what procedures need to be upgrade This may result in upgrading l&C procedures on as needed basis after completing the TPU.10 Ground Water Intrusion Control and Reclamation Projects 4.11 During the past eighteen months, the licensee has implemented improvements to prevent ground water intrusion into areas that contain safety related equipmen The areas around the RWSTs and chemical addition tanks have been regraded and paved to direct water away from the safeguards building The joints in the auxiliary building basement have been resealed and the ground water pumping systems have been repaired and/or improve Ground water monitoring systems have been installed that will allow the licensee to trend the effectiveness of these improvement In addition, the licensee has continued to improve station appearance through a number of reclamation project Painting walls, refinishing floors and/or replacing insulation have been accomplished in the auxiliary building basement and boric acid pump flats, Unit 2 safeguards building and condensate polishing buildin Pressurizer Safety Valves On numerous occasions, leakage past the PSVs has resulted in operational problems that have resulted in unplanned shutdowns.and outages to make repairs. Modifications to reduce PSV seat leakage were completed on Unit 1 during the 1994 RFO and in Unit 2 during the 1994 SGCC outage. This modification resulted in significant improvement in operating the units by eliminating PSV seat leakage and the inspectors concluded that corrective actions implemented to reduce PSV seat leakage were goo Within the areas inspected, one URI with two parts was identifie.

PLANT SUPPORT {71750, 71707)

Plant Tour Observations The inspectors toured the protected area and noted that housekeeping within the turbine, security, auxiliary, and safeguard buildings was excellent. Temporary equipment used for the Unit 1 SGCC outage was promptly removed from the protected are Containers for SGCC waste chemicals were segregated for future waste processing. Site preparations for the February 1995 Unit 2 RFO {e.g., scaffolding and

• work site prestaging) proceeded without incident. Significant restoration and preservation activities were completed in the auxiliary building lower level. Contaminated areas within the auxiliary building were promptly restored to clean standards following completion of preservation activities. This improved component visibility and thereby enhanced operator ability to evaluate equipment condition during routine tour Within the areas inspected, no violations or deviations were identifie.

Safety Assessment and Quality Verification {40500)

Unit 1 Post Trip Review The licensee conducted a post trip review using procedure VPAP 1404, Reactor Control, revision 0-PSOl, to evaluate equipment response to the trip and assess readiness for restart. The review team interviewed personnel, evaluated pertinent reactor and secondary plant performance data, and prepared a post trip review repor The team determined that the root cause of the trip was overtorquing of a teflon bushing on the oil return line from the 1-FW-P-lB main feed pump inboard motor inboard bearin The bushing failed, causing 1-FS-P-lB to trip on low lube oil pressur Unit 1 subsequently tripped on low SG water leve The team concluded that with the exception of the TDAFWP, all safety-related components responded to the trip as designe The inspectors observed the operating shift post trip debriefin Plant conditions and responses to the event were thoroughly discusse The inspectors noted that VPAP 1404 did not clearly communicate expectations for when the various debrief methods {e.g., oral shift debrief, individual debriPfs, and written statements) were to be use The supervisor SNS stated that written statements from the operating shift were intended for complicated trips involving multiple equipment failures or human performance issues. Oral debriefings were considered appropriate for straight forward trips and transients such as the January 8 trip. The supervisor SNS initiated an appropriate revision to VPAP 1404 to address this observation and other identified minor discrepancies. Additionally, the inspectors independently reviewed post trip data and interviewed personnel who prepared the post trip review repor The inspectors concluded that the post trip review had been thorough in both causal analysis and system response assessmen The details of the equipment discrepancy listing indicated that even minor anomalies had been properly evaluated and correcte The post trip review report was presented to SNSOC on January 1 The inspectors attended the presentation to determine whether the post trip review results were clearly communicated to station management and thoroughly assessed prior to restart authorizatio The initiating event, plant response, and corrective actions taken were discussed in detail and clearly understoo Several recommendations regarding follow-up corrective actions were presente One restart issue, cause and correction of the TDAFWP overspeed trip, was identifie The inspectors concluded that the licensee had effectively assessed the cause and station response to the January 8 reactor tri Within the areas inspected, no violations or deviations were identifie.

Action on Previous Inspection Items (92701, 92702)

(Closed) Deviation 90-22-01, Safety-Related Instrumentation Which Does Not Meet RG 1.97 Criteria for Electrical Isolation and Seismic Qualification This item identified an undocumented deviation from Regulatory Guide 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plant and Environs Conditions During and Following an Accident, revision The deviation's examples included commercial grade Hagan 107 indicators and Westinghouse Optimac 101 recorders which were used in RG 1.97 applicable instrumentation loops without appropriate seismic qualificatio Additionally, Category 1 and 2 instrumentation loops interfaced the plant computer without qualified isolation device The licensee's responses to the deviation dated October 8 and December 19, 1990, stated that the commercial grade devices would be analyzed by the SQUG methodology and either seismically qualified or replaced with qualified devices. Additionally, an isolation study would be conducted to evaluate isolating the plant compute The seismic analysis was documented in Engineering Report N R-001, Seismic Verification of Recorders and Indicators at the Surry and North Anna Power Stations, dated June 26, 199 The analysis determined that the mounting design of the recorders and indicators was adequate to sustain anticipated seismic events. During the SQUG walkdowns; however, five devic~s were identified which did not meet the vender recommended mounting configuration. Their operability was appropriately evaluated and work orders were initiated to install the missing mounting bracket The work was completed on August 24, 199 The licensee's isolation study of the plant computer concluded that no credible accident would cause a loss of electrical isolation between the plant computer and instrument loop This information was submitted to the NR A NRC letter to the licensee dated May 19, 1993, stated that the Surry conformance to the RG 1.97 criteria for isolation of the plant computer was acceptabl The inspector concluded that the licensee had completed the corrective actions specified in their response to the deviation and the issue was adequately resolve Within the areas inspected, no violations or deviations were identifie.

Exit Interview The inspection scope and findings were summarized on January 24, 1995, with those persons indicated in paragraph The inspectors described the areas inspected and discussed in detail the inspection results addressed in the Summary section and those listed belo.

..

Item Number URI 50-280/94-33-01

Status Open Description/(Paraqraph No.)

Issues Relating to TDAFWP failure (paragraph 4.2).

DEV 50-280, 281/90-22-01 Closed Safety-Related Instrumentation Which does Not Meet RG 1.97 Criteria (paragraph 7).

Proprietary information was reviewed during this inspection but is not contained in this report. Dissenting comments were not received from the license.

Index of Acronyms and Jnitialisms AFW AVS CDE CFR CST DEV DR ECCS EDG ESF F

FME FOSAR GETARS GPM HP l&C IRPI LAN MFW MS MSTV NRC POTT PM PMT PORV PSIA PSIG PSV PT PZR QA RCE RCP RCS RG AUXILIARY FEEDWATER AUXILIARY VENTILATION SYSTEM CAUSE DETERMINATION EVALUATION CODE OF FEDERAL REGULATIONS CONDENSATE STORAGE TANK DEVIATION DEVIATION REPORT EMERGENCY CORE COOLING SYSTEM EMERGENCY DIESEL GENERATOR ENGINEERED SAFETY FEATURE FAHRENHEIT FOREIGN MATERIAL EXCLUSION FOREIGN OBJECT SEARCH AND RETRIEVAL GENERAL ELECTRIC TRANSIENT ANALYSIS RECORDING SYSTEM GALLONS PER MINUTE HEALTH PHYSICS INSTRUMENTATION AND CONTROL INDIVIDUAL ROD POSITION INDICATION LOCAL AREA NETWORK MAIN FEEDWATER MAIN STEAM MAIN STEAM TRIP VALVE NUCLEAR REGULATORY COMMISSION PRIMARY DRAIN TRANSFER TANK PREVENTIVE MAINTENANCE PREVENTIVE MAINTENANCE TEST POWER OPERATED RELIEF VALVE POUNDS PER SQUARE INCH ABSOLUTE POUNDS PER SQUARE INCH GAUGE PRESSURIZER SAFETY VALVE PERIODIC TEST PRESSURIZER QUALITY ASSURANCE ROOT CAUSE EVALUATE REACTOR COOLANT PUMP REACTOR COOLANT SYSTEM REGULATORY GUIDE

..

RO RPM RWST SALP SG SGCC SI SNS SNSOC SQUG SRO ss STA TDAFW TDAFWP TM TPUP TS TSCS URI VPAP WO WR

REACTOR OPERATOR ROTATIONS PER MINUTE REFUELING WATER STORAGE TANK SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE STEAM GENERATOR STEAM GENERATOR CHEMICAL CLEANING SAFETY INJECTION STATION NUCLEAR SAFETY STATION NUCLEAR SAFETY AND OPERATING COMMITTEE SEISMIC QUALIFICATION UTILITIES GROUP SENIOR REACTOR OPERATOR SHIFT SUPERVISOR SHIFT TECHNICAL ADVISOR TURBINE DRIVEN AUXILIARY FEEDWATER TURBINE DRIVEN AUXILIARY FEEDWATER PUMP TECHNICAL MANUAL TECHNICAL PROCEDURE UPGRADE PROGRAM TECHNICAL SPECIFICATIONS TURBINE SPEED CONTROL SYSTEM UNRESOLVED ITEM VIRGINIA POWER ADMINISTRATIVE PROCEDURE WORK ORDER WORK REQUEST