IR 05000280/1990030

Insp Repts 50-280/90-30 & 50-281/90-30 on 900930-1027.No Violations Noted.Major Areas Inspected:Plant Operations, Maint,Surveillance,Ler Closeout,Action on Previous Insp Findings & Licensee Self Assessment

ML18153C462
Person / Time
Site:	Surry
Issue date:	11/23/1990
From:	Frederickson P, Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML18153C461	List: IR 05000280/1990030 ML18153C460
References
50-280-90-30, 50-281-90-30, NUDOCS 9012100317
Download: ML18153C462 (21)

Text

Report Nos. :

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTA STREET, N.W.

. ATLANTA, GEORGIA 30323 50-280/90-30 and 50-281/90-30 Licensee:

Virginia Electric and Power Company 5000 Dominion Boulevard Glen A 11 en, VA 23060 Docket Nos.:

50-280 and 50-281

.License Nos.:

DPR-32 and DPR-37 Facility Name:

Surry 1 and 2 Inspection Conducted:.

September 30 through October 27, 1990 Inspectors:W. E. H~~r ~it'int Inspector J. w. York,~ Inspector S. G. 4~~

Ting~nt Inspector Accompanying Inspector:

M. D. Hun~

• Approved by:

. fl/ Y~e..

P. E.. FredricKson, Section Chief Divisiori of Reactor Project~*

SUMMARY Scope:

• /~bu 1)ateS i gned

.J-',&~/f?o Date Signed This routine.resident inspection was conducted on site in the areas of plant operations, p 1 ant maintenance, p 1 ant * survei 11 ance, 1 i censee everit report closeout, action on previous inspection findings, licensee seJf assessment, traceability of repaired instrument modules, Instrumentation and Control procedure upgrade program, Main Control Room Appendix R seals, and installation and testing of modifications. *During the performance of this inspection, the resident inspectors conducted review of the licensee 1s backshift or weekend operations on October 6, 8, 9, 13, 14, 15, 21, 22,, 24, and 26, 1990.

. Results:

In the area of operations, a weakness was identified involving the.*

administrative process for i.nvolvement of engineering support in determining the operability of safety-related equipment (paragraph 3.a).

In the area of surveillance, one weakness and two strengths were identified.

The weakness involved not providing adequate attention to a quality assurance 3 17 901126 9012100 05000280 PDR ADOCK PNU G

assessment conclusion in the area of safety valve setpoint testin A strength involved the licensee's voluntary action to upgrade its safety and relief valve setpoint program (paragraph 5.a).

The second strength involved improvements in the performance of emergency_bus load sequence testing (paragraph 5.c).

• In the area of engineering/technical support, a weakness was identified regarding a lack of incorporation of Virginia Power Administrative Pro-cedure 0804 requirements into Periodic Test 1-PT-13.4 prior to inspector identification (paragraph 5.a).

One inspector followup item was identified on licensee corrective action and testing -for defi_ciencies identified during recirculation spray heat exchanger service water flow testing (paragraph S~b). Persons Contacted Licensee Employees REPORT DETAILS B. Allen, Supervisor, Shift Operations

• W. Benthall, Supervisor, Licensing

• R. Bilyeu, Licensing Engineer D. Christian, Assistant Station Manager

• J. Downs, Superintendent of Outage and Planning D. Erickson, Superintende~t of Health Physics

• R. Gwaltney, Superintendent of Maintenance

• D. Hart, Supervisor, Site Quality Assurance

• M. Kansler, Station Manager T. Ke.ndzia, Supervisor, Safety Engineering

• J. McC~rthy, Superintendent of Operations*

• A. Price, Assistant Station Manager

• E. Smith, Site Quality Assurance Manager

• T. Sowers, Superintendent of. Engineering*

• J. Yaffey, Maintenance Engineer NRC Personnel

• P. Fredrickson, Section Chief, DRP, RII

• Attended exit intervie Other licensee employees.contacted included control room operators, shift technical advisors, shift supervisors and other plant personne Acronyms and initfalisms used throughout this report are listed* in the last pa~agrap * Plant Status Unit 1 began the reporting period at approximately 57% powe The unit continued to operate in a coastdown mode until October 6, when the unit commenced. a routine shutdown and.refueling outag On October 13, the unit entered reduced inventory operation and exited reduced inventory operation on October 1 Reduced inventory operation is further discussed in paragraph *3. The unit was in day 22 * of the outage when the i nspec-t ion period ende Unit 2 began the reporting period at powe The unit operated at power until October 23, when the unit was shutdown and cooled down to less than 200 degrees Fahrenheit because testing in Unit 1 revealed that service water flow through the RSHXs was less than the design basis. Service water testing of Unit 1 RSHXs is further discussed in paragraph 5.b.. Unit 2 was in day 5 of the unscheduled outage wh~n the inspection period ende *.*,-

I

2 Operational Safety Verification (71707 & 42700) Daily Inspections The inspectors conducted daily inspect ions in the fo 11 owing areas:

control room staffing, access, and operator behavior; operator adherence to approved procedures, TS, and LCOs; examination of panels containing instrumentation and other reactor protection system elements to determine that required channels are operable; and review of control room operator logs, operating orders, plant deviation reports, ta gout logs, temporary modification * 1 ogs, and tags on components* to verify compliance with approved procedures.* The inspectors also routinely accompanied station management on plant tours and observed the effectiveness of their influence on activities being performed by plant personne On October 13 at * 3: 30 a. m., operators noted * that service water pump 1-VS-P-lC was vibrating excessively. and that the discharge pressure was lower than normal.

The pump was secured and restarted at 11:55 Pump vibration levels were then measure Results of the vibration measurements indicated that the pump's vibration levels had significantly increased from previously measured data.. Ope rat ions personnel determined that the pump was operable because the discharge flow rate and pressure were within acceptable procedural limit There were no p~oc~dural specifications for vibration levels.,from October 13 to October 17, the pump was considered to be operable, but was not utilize On October 17, the pump was replace Inspection of the pump after removal indicated the the. i mpe 11 er was rubbing against the wear ring and that there was excessive rust 01'! the lower motor bearin The licensee was in the process of performing a component failure evaluation on the pump when the inspection period ende *

The 1-VS-P-lC pump is one of three safety-related pumps that provide service water to the control room and emergency switchgear room ventilation air conditioning syste TSs require that all three of these pumps be operabl These pumps are not in the-licensee's 1ST program because they are not i nsta 11 ed in a ASME Cl ass 1, 2 or 3 syste The inspectors consider that the decision by operations personnel on October 13 that the 1-VS-P-lC pump was bperable was nonconservative because the increased vibration levels were not evaluated by engineering. Engine~ring ~valuation of the increased vibration levels would have provided justification why the levels were acceptable o would have. conclude-d that the pump was inoperabl The lack of engineering involvement is considered a weakness in the area of operations because no administrative process exists for the involve-ment of engineering support in determining the operability of safety related equipmen *.

j

• On October 22 during a routine sampling evolution, air was discovered in* the casing of containment spray pump 2-CS-P-1 The air was vented from the pump's casing and the pump was considered operabl Deviation report 52-90-545 was written to document this proble The deviation report stated that the pump's discharge piping was drained for maintenance on October 15, and that the pump was tested satis-factory on October 1 The deviation report also stated that it was suspected that air in the discharge piping had migrated over the past

• week into the pump's casin On October 23, at the request of engineering, the pump I s casing and discharge piping were vente During this venting evolution, water issued from the pump casing vent but air initially issued from the pump's discharge piping..

When e~gineering became involved, they requested further actions to ensure that air migration issue was completely evaluated by checking both the pump casing and the discharge pipin Since 2-CS-P-18 pump is a safety-related pump and is required to be operable by TSs, the inspector considers that the pump's operability determination, made on October 22, by ope rat ions without input from engi neeriilg was nonconservativ The lack of an administrative process and the non-involvement of engineering support by operations in determining operability issues for safety-related equipment, is another example of a weakness in the operations are~.

The. operability issues for 2-CS-P-18 and 1-VS-P-lC pumps were discussed with the Operations Superintenden He agreed that engineering support should have been requested by operations for determining the operability of these two pumps and that this weakness would be evaluated furthe Weekly Inspections The inspectors conducted weekly insp.ections in the following areas:

operability verification of selected ESF systems by valve alignment, breaker positions, condition. of equipment or component, and oper-ability of instrumentation and support items essential to system actuation or performanc Plant tours were conducted which included observation of general plant/equipment conditions, fire protection and preventative measures, control of activities in progress, radia-tion protect ion contra ls,, physical security contra ls, p_l ant house-keeping conditions/cleanliness, and missile hazard The inspectors routinely noted the temperature of the AFW pump discharge piping to ensure increases in temperature were being properly monitored and evaluated by the license Biweekly Inspections The inspectors conducted biweekly inspections in the following areas:

verification review ahd walkdown of safety-related tagouts in effect; review of sampling program (e.g., primary and secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples);

observation of control room shift turnover; revjew of implementation of the plant problem identificati-0n system~ verification of s~lected port ions of containment i sol at ion lineups; and verification that notices to workers are posted as required by 10 CFR 1 Other Inspection Activities Inspections included areas in the Units 1 and 2 cable vaults, vital *

battery rooms, steam safeguards areas, emergency switchgear rooms, diesel generator rooms, control room, auxiliary building, Unit 1 containment, cable penetration areas, independent spent fuel storage facility, low level intake structure, and the safeguards valve pit and pump.pit areas. RCS leak rates were reviewed to ensure that detected or suspected leakage from the system was recorded, investi-

-gated, and evaluated; and that appropriate actions were taken, if -

require The inspectors routinely independently calculated RCS leak-rates using the NRC Independent Measurements Leak Rate Program (RCSLK9).

On a regular basis, RWPs were reviewed, and specific work activities were monitored.to assure they were being conducted per the RWP Selected radiation protection instruments were periodically checked, and equipment operability and calibration frequency were verffie * Physical Security Program Inspections In the course of monthly activities, the inspectors included a review

. of the licensee's * physical security pr-0gra The performance of.

various shifts of the security force was observed in the conduct of daily activities to include: protected and vital areas access controls; * searching of personnel, packages and vehicles; badge issuance and retrieval; escorting of visitors; and patrols and compensatory post No discrepancies were note Review of Requirements.and Actions for Reduced Inventory Conditions During. this period, the inspectors conducted a review of the licensee's responses and implemented actions with regards to the requirements of Generic Letter 88-17, Loss of Decay Heat Remova *The review was conducted prior to the licensee's entry into a reduced inventory condition as defined in the generic letter. The specific items reviewed were:

Generic -Letter 88-17 - The inspectors reviewed the subject letter including the licensee's response to the letter dated January 6, with supplemental responses dated February 3, September 29, October 31, 1989; and October 5, 199 Administrative Controls -

The inspectors monitored lic_ensee *

meetings which reviewed the sequence of events for placing the unit in a reduced inventory condition and discussed controls and

procedures in affect to control reduced inventory _operation with Operations and Station Managemen Containment Closure Activity - The licensee's procedures require that the status of the containment configuration be est_ablished and verified prior to entering a reduced inventory conditio In addition, the procedure for loss of RHR capability directs containment closure action to be initiated and continued until the RHR system is returned to service and core conditions are verified norma The inspectors verified that the licensee has prepared procedures to reasonably assure that containment closure will be achieved prior to the time that the core would be uncovere This was done by reviewing 1-0P-3.4, Draining the Reactor Coolant System, dated January 25, 1990; 1-0P-lG, Refueling Containment Integrity and RCS Mid-Loop Containment Closure Checklist, dated April 28, 1989; and AP-27, Loss of Decay Heat Removal Capability, dated September 27, 1988..

RCS Temperature - 'The inspectors verified that the controlling procedure for draining the RCS, 1-0P-3.4 required at least two incore temperature indicators be operable prior to draining the RCS to a reduced inventory conditio The inspectors al so verified that the control room operators periodically (every six hours} recorded the temperatu~es in their log (periodic test l-PT-36, Instrument Surveillance).

In addition a supplemental check list, Control Room Operator Reduced RCS Inventory Relief Checklist, requires at least two core exit thermocouples be operable (i.e. one from each train).

RCS Level Indication - The licensee has installed one means of level i ndi cation which provides continuous readout in the control rooi The inspectors verified that the system also provides a low level alarm for loss of level and is calibrate In a letter dated October 31, 1989, the licensee committed to install a second means _of RCS level indication during the present Unit 1 refueling outag RCS Perturbations - The inspectors verified that the licensee has a procedure, OC-28, Assessment of Maintenance Activities for Potential Loss of Reactor Coolant Inventory dated March 21, 1989, which allows for operations assessment of work on systems for potential loss of reactor coolant inventory during reduced RCS inventory condition RCS Inventory Addition - The inspectors verified that procedure l-OP-3.4 required at least two available and operable means of adding inventory to the RCS in addition to the RHR syste The procedure requires that in a reduced inventory condition, one charging/safety injection pump and one low head safety injection pump must be. available with appropriate flowpaths to the cor *

_ Loop Stop Valves -

The licensee utilizes RCS loop isolation valves for loop isolatio Nozzle d~ms are not use The inspectors verified that the licensee uses an ope rational checklist to ensure that the RV upper plenum is adequately vented when maintenance activities require opening of a RCS cold leg pressure boundar During reduced inventory operation, one RCS loop was maintained unisolated ~ith its* loop bypass ope Contingency Plan_s to Repower Vital Susses -

The vital -and emergency electrical distribution system receives offsite power from the three reserve station service transformers during normal plant operation The-RHR pumps and the CCW pumps (which coo1 the RHR heat exchangers) operate off stub busses attached to the lJ and lH emergency busse The stub busses are attached to these emergency buss es. * The stub busses are shed during degraded or undervoltage situations; but can be reconnected to the emergency busses by closing a breake The equipment for th_e two additional means for -adding* inven:tory to the RCS, charging pumps and low head safety injection pumps, are powered from the emergency busse The number 1 EOG supplies power to the lH emergency bus in case of a degraded or undervo l tage -

situation, and the number 3 EOG supplies power to the_ lJ bu During this period, the licensee had both EDGs f9r the Emergency

- busses operable* and both reserve station service transformers (offsite preferred power) powering-the emergency busses. *

Unit 1 entered a reduced inventory condition on October 13, 1990 in order to drai.n the steam generator tubes in preparation for steam generator tube eddy current testin RCS level was increased.out of the reduced inventory condition approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> latte No discrepanties were note * Licensee 10 CFR 50.72 Reports On October 23, 1990, the licensee*made a report in accordance with 10 CFR so.12-concerning entry into the station emergency plan (NOUE) for a TS-required shutdown of Unit The shutdown was required when the licensee cone l uded that service water fl ow through two RSHXs on Unit 1 was less than the design basis required flo The licensee was conducting flow testing of the service water flow through the RSHXs in accordance with a special test when this condition was identified. The reduced service water flow through the RSHXs was considered generic to Unit Unit 2 commenced a routine shutdown from 100% power at approximately 0120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> and was in cold shutdown by 0830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br /> on October 24 when the NOUE was terminate Testing of Unit 1 RSHXs is further discussed in paragraph Within the areas inspected, no violations were identifie **

7 Maintenance Inspections (62703 & 42700)

During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedure Inspection areas included the following: Lube Oil Cooler Replacement on Charging Pumps On May 30, 1990, the licensee replaced the lubrication oil cool er on Unit 2 charging pump 2-CH-P-l This cooler uses service water to cool the oil from the gear bo On September 6, 1990, this same lube oil cooler had to be replace The licensee's materials engineering laboratory performed a metallurgical analysis of three tubes taken from the cooler although only one tube was leakin The results of this analysis were discussed in a meeting attended by the inspectors on October 10, 199 The following reasons were g*iven for the tube failure:

A protective copper oxide layer had not developed on the new cooler tube A sulfide producing bacteria found in the brackish cooling water migrated onto the tubing surf~ce causing a random pitting type attac The service water side became stagnant which accelerated the sulfide corrosio The one tube that was leaking had a 1/16 inch hole and the other two tubes had pits that would have penetrated through the wall in a short period of tim On September 29, 1990, another charging pump, 1-CH-P-lA, had a failure of the oil cooler, which had also been in service approxi-mately two month This coo)er also had a leaking tube/tube The licensee also had the cooler for charging pump 1-CH-P-lB fail within the last two months, but it had been in service for approximately five year This cooler did not have a leaking tube but failed because of marine growth and silt that degraded the heat removal capability below the acceptance limi The difference between this oil cooler and the coolers that failed after approximately two months of service was that the tubes and tubesheets had been coated with a special epoxy coatin The licensee has decided to replace all the oil coolers with coolers having the corrosion resistant coatin Removal of Service Water MOVs On October 26, the inspectors witnessed the removal of MOVs 1-SW-MOV-103C and 1-SW-MOV-103 The valves and operators were removed to support SW piping inspection This maintenance was accomplished in accordance _with DCP-90-26-1, HX* Service Water Piping

• Cleaning and Recoating-Surry Unit 1, dated October 2, 1990*.

The inspectors reviewed the tag-out, verified that all procedure revisions were properly entered, verified that the maintenance was accomplished per the procedure, and witnessed portions of the main-tenanc No discrepancies were note Within the areas inspected, no violations were identifie.

Surveillance Inspections (61726 & 42700)

During the reporting period, the inspectors reviewed various surveillance activities to assure compliance with the appropriate procedures as follows:

Test prerequisites were me Tests were performed in accordance with approved procedure Test procedures appeared to perform their intended functio Adequate coordination existed among personnel involved in the tes Test data was properly collected and recorde Inspection areas included the following: Unit 1 Main Steam Safety Valve Testing On October 3, 4, and 5, the licensee tested Unit 1 main steam safety valves in accordance with procedure l-PT-13.4, Main Steam Safety Valve Setpoint Verification, dated October 2, 199 This procedure was a new procedure, but was not issued as an upgraded procedur The purpose of this test is to verify the operability of main steam safety valves MS-SV-101A, B, C; MS-SV-102A, B, C; MS-SV-103A, B, C; MS-SV-104A, B, C; and MS-SV-105A, B, C by measuring valve setpoint and checking for seat leakag The inspectors observed setpoint testing, reviewed the completed procedure, and reviewed setpoint calculation Results of the inspectors' review indicated that the testing was accomplished in accordance with the procedure and that the setpoint calculations were correct. During this review, the inspectors noted that not a 11 of the requirements of the licensee I s admi nstrat i ve-procedure that governs safety valve testing had been incorporated into l-PT-1 VPAP-0804, Safety and Relief Valve Program, dated July 2, 1990, provides the technical requirements for testing safety and relief valves. VPAP-0804 requirements to stabilize valve temper-ature prior to testing, install a tamper seal after test completion, and have an independent observer verify setpoi nt were not i ncor-porated into l-PT-1 The inspectors informed the licensee of these omitted requirements and the test protedure was changed prior

to the performance of the test. Procedure 1-PT-13.4 was written.by onsite engineering. personne The inspec:tors consider that a weakness in the area of engineering/technical support existed regarding not fully incorporating VPAP-0804 requirements into 1-PT-13.4 prior to inspector identificatio During the period of September 5 through 13, 1990, the licensee's QA organization performed an assessment of the safety and relief valve program. * The conclusions of this assessment were presented to management on September 1 One of the items of this assessment was that not all of the requirements of VPAP-804 were incorporated into procedure MCM-0434-02, Setpoint Test of Safety and Relief Valve This item is similar to the inspectors' finding previously discussed in that the licensee's safety valves test procedures do not contain ali the requirements of VPAP-080 The inspectors consider it a weakness that the licensee's corrective action in *response to this QA 1s assessment item involving incorporation of VPAP-0804 require-ments did not prevent 1-PT-13.4 from having the same deficienc The inspectors' review of VPAP-0804 did identify a strength in the licensee's safety and relief setpoint progra VPAP-0804 contains the latest industry standards for setpoint testing valves and signi-ficantly exceeds the minimum requirements for setpoint testing valve The licensee's action to voluntarily upgrade their safety and relief valve setpoint program was identified as a strengt Flow Testing of the Service Water Side of Unit 1 Recirculation Spray Heat Exchangers Band During this inspection period, the inspectors witnessed flow testing of the subject heat exchangers in accordance with special test procedure l-ST-290, Recirculation Spray Heat Exchangers Service Water Flow Test, dated October 5, 199 The purpose of this test was to collect data in order to determine that design basis accident flow and long term cooling is adequate to remove design basis heat loads from containmen The test was also conducted to collect data necessary to validate pressure drop values provided-by the manu-facturer and to estimate reduction in heat transfer capability due to macrofoul in The test involved removal of l-SW-104-B and -C service water valves and their respective expansion joints,* and the installation of special venturi test spools in their places to measure system flo In addition, pressure taps were installed in the system piping upstream of.the l-SW-104 and l-SW-105 valve locations in order to measure accurate differential pressures across the RSHXs during test flow condition After completion of installation of test equipment, the system was filled and vented with service wate On October 15, flow was initiated through the Unit 1, Band C RSHX.

The inspectors monitored the testing and noted that preliminary test I

I

-*

data indicated that flows were lower than expecte The inspectors specifically noted and recorded indicated flows and pressure drops through the heat exchangers as follows:

DATE 10/15 10/15 TIME 1800 1800 RSHX ID

C FLOW RATE DIFF PRESS 5450 GPM 161 inches H20 6400 GPM 164 inches H2o The inspectors were informed at this time that expected pressure drops across the heat exchangers should have been approximately 60 inches H The inspectors also noted that flow indication for opera tort in the contra l room was not prope The SW fl ow header being tested had flow indication in the control room for the combined inlet flows to RSHXs B and C (1-SW-FI-1058).

In addition, individual flow discharge indication was ~rovided for RSHX B (l-SW~FI-1068) and RSHX C (l-SW-FI-106C).

The inspector recorded the following flow indication in the control room when the system was aligned for full flo Flow indication from the installed test venturis was essen-tially the same as recorded on October 15 at 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> as indicated above.

CR-Indicator CR-Indicator CR-Indicator 1-SW-FI-1058 l-SW-FI-1068 l-SW-FI-106C Combined Flow Flow Flow DATE TIME B&C RSHXC 8/RSHX C RSHX 10/15 0745 16,000 GPM*

0 GPM 0 GPM

• Pegged High Later, during the testing, after the flows had been throttled several times by closing and then reopening both 1-SW-105-8 and -C valve The following indicated flows and differential pressures from test equipment, installed specifically for the test, were recorded:

DATE 10/16 10/16 TIME 0845 0845 RSHX ID B

C FLOW RATE 7941 GPM 8144 'GPM DIFF PRESS 138 inches H2 inches H2o The inspectors noted that al though fl ow rates had increased and differential pressures had decreased, the pressures still appeared hi~her than expecte The licensee secured this test on October 16, and commenced draining of the RSHXs flow paths in order to conduct inspections of the heat exchangers for any blockag The licensee inspected the RSHXs inlet heads on October 19 and determined that there was minimal blockage of the heat exchangers' tubesheet However, there was a layer of

material (rust flakes, marine growth, crabs) in the bottom of each heat exchanger inlet bow The inspectors. accompanied the_ 1 i censee on these inspections and agreed with the finding After additional evaluations and discussions, the licensee recommenced flow testing on the service water side of the ~ubject RSHX This test, which was conducted on October 22, initiatad flow to the reci rcul at ion spray service water with the system in a configuration that would be expected during an actual acciden Initial test conditions involved t_he flowing of three of the four condenser waterboxes (A, B, and D) 'throttled to approximately half*

flow (approximately 100,000 GPM each)~

The SW header for the Band C RSHX from the 1-SW-103 inlet valves to the 1-SW-105 outlet valves including the heat exchangers was in a dry layup conditio Test instrumentation was isolated and the test was initiated from the control room by opening the 1-SW-103-B and -C and *1-SW-105-B and -c" valves and then immediately closing the i_solation valves for flow through the condenser waterboxe *

The* inspectors monitored the test i niti at ion from the control room and observed that control room indication was still not providing reliable flow readou The following data from CR indicators was recorded approximately one hour after flow was initiate DATE 10/22 TIME 1430 CR INDICATOR CR.INDICATOR 1-SW-FI-105B 1-SW-FI-106B 0 GPM O GPM CR INDICATOR 1.:.sw-FI-106C 0 GPM During this test, flow rates (from text equipment gages that were installed specifically for the test) for the first few hours of the test were lower than that recorded in past testin Flows that were

• measured were approximately 4100 GPM and 2100 GPM for the B and C RSHXs respectivel The test was.continued for approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and flows were throttled through the heat exchangers by opening and closing both. the 1-SW-105-B and -C valves several times as was done in the first tes After eye 1 i ng of these va 1 ves, flows were observed to increas After evaluation of these test results, the licensee concluded that the flowrates of SW through the RSHXs were less than the design basis required values and declared the recirculation spray system for Units 1 and 2 inoperabl This condition resulted in a TS required shutdown of Unit 2 from 100% powe The shutdown is discussed in paragraph On O~tober 25~ the licensee conducted an inspection of the Band C RSHXs SW inlet heads and determined that hydroids were present on the tubesheets of both heat exchangers and also tn the bowls of the heat exchanger The inspectors accompanied the licensee on this inspection and agreed with the fiflding Additional licensee

inspections accomplished. on the Unit 1 SW flowpath to the RSHXs identified significant hydroid presenc* Additional inspections were ongoing on both Unit 1 and Unit 2 when the inspectio~ period ended. *

The inspectors consider that the flow testing results as of the end of the inspection period have identified the following *issues/

concerns that should be addressed:

A determination of the reduced flow through the recirculation spray heat exchangers for each test should be evaluated and the root, cause of the flow degradation should be corrected.* In addition, adequate testing should be accomplished in order t verify that corrective action has been effectiv *

Corrective action for incorrect indication of control room flow instrumentation should be a~complished and adequate testing should be accomplished in order to verify that corrective action has resolved this proble *

The inspectors concerns were discussed with station management and will be identified as an inspector followup item (280, 281/90-30-01), -

Followup on licensee corrective action and testing for deficiencies identified during RSHX SW flow testjn Emergency Bus IH Testing*

On October 9, 1990 the licensee performed procedure I-OPT-zz~oo2, ESF Actuation With Delayed (5 minutes) Under Voltage - IH Bus, dated October 5, 199 The purpose of this test is to conduct a functional test of the sequencing of.1 oads onto emergency bus IH when an ESF signal is i riduced, fo 11 owed by an undervo l tage signal five minutes late This procedure also tests Trafn A CLS HI, CLS HI-HI, and SI manual actuation switche The inspectors attended the pretest brief, observed the test from the contra l room, and reviewed the completed test procedur This testing is performed each refueling outage on the H and J emergency buse During previous. performances of this test, deficiencies were identified by NRC inspectors which included the licensee's lack of a thorough understanding of the test procedure, poor coordination and communication between the test director and operations personnel, an inadvertent ESF actuation due to an inade-quate procedure, and a lack of attention. to detail by personnel performing the tes During the performance of this test on October 9, the inspectors noted that the above deficiencies did not occur and considered that the test was performed in an efficient manne.The improvement in the performance of this test from *

previous tests indicates that corrective actions for past problems has been effective and was noted as a strengt Main Station Battery 18 Refueling Service Tes On October 23, 1990, the inspectors * witnessed the performance of periodic test 1-EPT-0106-02, Main Station Battery 18 Refueling Service Test, dated October. 19, 199 This periodic test ensures that TS sections 4.6.C.1.e and 4.6.C.1.f requirements are satisfie The test is performed during normal refueling shutdown and requires

. that each battery be subject to a simulated load test without the

. battery charge The inspectors reviewed the procedure, discussed the te*st with the *system engineer, and observed part of the testing in the emergency switchgear roo No discrepancies were.note Within the areas inspected, no violations were*identifie.

Licensee Event Report Review (92700)

The inspector *reviewed the LER I s 1 i sted below to ascertain whether NRC reporting requirements were being met and to evaluate initial adequacy of the correctiv*e action The inspector's review also included followup on imp 1 ementat ion of corrective action and review of 1 i censee documentation that all required corrective actions were complet (Closed) LER 281/90-04,.Unit 2 Manual Reactor Trip Following Inadverte Grounding of the A Main Feedwater Regulating Valve Control Signal During Testin This issue involved a manual reactor trip of Unit 2 from approximately 100% power due to surveil 1 ance testing of the ERF computer MUX power supply causing the A main feedwater regulating valve to inad-vertently shu This event was discussed in Inspection Report 280, 281/90~2 In that report~ the trip and licen~ee corrective actions prior to the unit restart were reviewed and discusse The inspectors consider that. the-licensee's corrective actions were adequat Within the areas inspected, no violations were identifie.

Action on Previous Inspection Findings (92701, 92702)

(Closed) IE Bulletin 83-07, Apparent Fraudulent Products Sold by Ray Miller, Incorporate The licensee responded to the initial NRC notification (before the issuance of the bulletin and its supplements) in a 1 etter dated February 9, 1983. *.The final response was dated Apri 1 5, 198 This response was reviewed by the Region II Materials and Processes Section and based upon their review the bulletin is considered close.

I&C Concerns (92701) Traceability of Repaired Instrument Modules An inspection was conducted during the week of October 15, 1990, to review the action$ taken by the I&C maintenance department to correct deficiencies identified during a February 12-16, 1990, inspection documented by Report 280,281/90-1 During that inspection a

).4 noncited violation was identified in the area of procedural control for storage, repair and installation control for control system component The licensee has issued a series of procedures that control the bench-work repair activities of the various modules that are part of the reactor protection control system. The procedures listed below are dedicated to the repair and recertification of Westinghouse control modules for the models and names listed below:

Procedures N O-ICM-MI-G-900 O-ICM-MI-G-902 O-ICM-MI-G-903 O-ICM-MI-G-904 O-ICM-MI-G-905T O-ICM.:.MI-G-906 O-ICM-MI-G-907 O-ICM-MI-G-909 O-ICM-MI-G-912 Name Model 118m V/I Amplifier Model 127-112 Multiplier/Divider (Steam Flow)

Model 127-112 Multiplier/Divider (Feed Flow)

Model 127-112 Multiplier/Divider (Tave Rod Control)

Model 113 Function Generator Model 110 Signal Isolator Model 111 Signal Summator Model 139-118 Signal Comparator Mag Amp Model 4111212 Remote/Manual Set Point StatiQn All procedures require documentation for the traceability of repair part There is also a QC inspection requirement included as part of the module repair proces The procedures require a "burn-in" period for repaired modules before full acceptance testing is completed and the modules are declared qualified for safety-related ci~cuit A minor discrepancy was noted during review of these procedure The

"burn-in" period is recommended to be 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> with a temperature of 110 degrees Fahrenheit(+ 10 degrees Fahrenheit).

There was not a provision for documenting the fact that the temperature was held at the prescribed value for the "burn-in 11 perio These procedures are explicit in the adjustments and voltages inputs and the voltages expected at the output of each modul With the exception of the mi nor discrepancy, the procedures, if fo 11 owed, should provide sufficient data to permit the use of the repaired modules in safety related application On October 15, 1990, Deviation Report SI-90-1329 was issued which stated that the station instrument shop was working on safety-related process e.ontro l modules under nonsafety-re lated work order This condition exists when a defective module is removed from a safety-related control or instrument loop and replaced with a functional modul The replaced module is no longer identified as part of the loop and fs then identified as a spare modul Since a spare module that can be used in either a safety-or nonsafety-related application has no mark numbers that classify the item as safety-related in the equipment list, the work order is identified as nonsafety-relate. ** r

On October 16, 1990, Stop Work Order SW-590-01 was issued to stop all repair work on control modules in the instrument shop until this

~ituation was clarifie The work order planning and tracking system identifies the equipment that is environmentally qualified and-or safety-relate Since the system did not have identification numbers for spared control modules, a safety-related work order would not be generate This further resulted in the warehouse often downgrading Class lE equipment to a nonsafety-related grade status to expedite *issuing repair parts against these nonsafety-related work order As a result of the stop work order being issued, the equip-ment list contained in the work order planning and tracking system was revised to include the various module part numbers for those modules that could be installed in the reactor protection control syste This action will result in all module repairs being per-formed on safety-related work orders which in turn will require the spare and repair parts issued by the warehouse to*be qualified as Class I This is a conservative action on the part of the license The licensee has several repaired control modules stored in locked cabinets for use in either safety-or nonsafety-related application Some of these modules have been in storage since 1988, and possibly longe Discussions were held with the licensee representatives regarding the acceptability of the modules for safety-related application The licensee advised *the inspectors that the status of these modules would be reviewed and action taken to assure th quality of module The licensee had committed to make corrections related to the repair and maintenance procedures for control modules as the result of a 1989 QA audit and the NRC inspection covered by Inspection Report 280,281/90-1 These changes and corrective actions are now scheduled for completion on February 1, 199 l&C Procedure Upgrade Program The licensee has begun an I&C procedure upgrade program to improve the performance and documentation of surveillance tests and plant corrective and preventive maintenance activitie The surveillance testing is performed by PT procedures, and is intended to prove TS complianc Calibration procedures provide the guidance for adjusting components and I&C loops to meet the PT requirements. This upgrade program involves an extensive review of all past history records, drawings, instrument loop scaling calculations, and design changes which might have a bearing on the overall loop values used for determining the * setpoi nts o*f components and loop ca 1 i brat ion The results of this review will be the development of procedures having numerical data that has been verified by the upgrade process, a numerical data reference system by procedure number that will show the source used for the setpoints values, and the calculation for instrument and loop tolerances, clearer definitions for the purpose of the procedures, and assurances that overlap testing exists between

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the pro~edures being upgraded and the next procedure to be p*erformed in* the testing sequence of. the channel functional requirement This upgrade program has resulted in some values in PT and calibra-tion procedures being changed and not.matching the older calibration*

data for certain instrument loop As more and more procedures are upgraded, it will be necessary that the technicians-be made aware of

• changes and understand the The upgrade program is intended to document equipment qualification requirements, establish repair and replacement standards and cause records to be developed for * his-tori cal data purpose This upgrade should provide for improved working procedures and the traceability of components in the deter-mination of operability of components in safety-related system.

. MCR Appendix ~ Seals (92701)

Ttie licensee performed a bottled air test of the MCR on:June 1, 1989, and found that higher than predicted air flow rates were necessary to achieve the required positive and differential pressur As a result, a consul.:.

tant performed cletailed walkdown inspections of the existing MCR pressure boundary penetration seals to evaluate the condition of ventilation seals, fire doors, electrical and fire barrier penetration seals. These walkdown evaluations also took into consideration NRC Information Notices sa..:04, 88~56, and 88-6 The criteria for acc~ptance was defined basically as silicone seals 10 inches deep and with no cracks. (openings) deeper than 3 inches by 1/4 inches wid Other types of penetration seals inspected wer~ piping sleeves with caps, and duct seals with flamastic filler. The inspection resulted in several station deviations being generate Th licens~e's engineering staff is in the.process of evaluating these devia-tions and will advise the NRC of the status of these penetrations and any deviati.ons from 10 CFR 50, Appendix R requirements by November 21, 199 In the meantime,* fire watches have been posted in the areas where the penetration seals are questionabl,

Review of Licensee Self Assessment Capability (40500)

During this inspection period, the inspectors attended several onsite SNso*c meetings and evaluated the 1 i censee' s ons i te program for continuing review of t_he operational and safety aspects of the nuclear facility as required by T~ 6.l~C.. During this period, Unit 1 had began a refueling outage involving special testing*of safety systems and several significant modifications to safety system The inspectors attended SNSOC meetings on October 16, 18*, and 25, and specifically'focused on the committee's attention to operating unit overview as compared to the outage unit items.

. The inspectors verified. that the meetings were in comp 1 i ance with TS requirements with respect to composition, q'uorum, meeting frequency, and review responsibilitie The meetings continued to be well coordinated by the chairman with only one issue being focused on at a tim The inspectors did note that addi ti oria l meetings were being held. each day due to the demands of outag~ schedule and changes of procedures requiring committee revie However, these additional meetings were controlled in such a manner that proper review was being accomplishe The inspectors

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consider that the committee meetings continue to be eff_ect i ve in accomplishment of review of the,operational and safety aspects of the facilit On October 16, 1990, the inspectors attended a meeting of the licensee's MSRC which was being held at the Surry Power Statio A TS change was approved this inspection period which made the MSRC the offsite review committe The MSRC is comprised of senior corporate and station manage-ment as well as several industry consultant Areas of discussion included loss of RHR combined with a loss of *offsite power, instrument air assessment (Surry), trends of problem areas causing limiting conditions for operations during the last twelve months, and review of 1989 LERs for trends. The inspector noted that the committee appeared to be fully functional and capable of accomplishing the required independent review Within the areas inspected, no violations were identifie.

Installation and Testing of Modifications (37828)

ATWS Mitigation System (TI 2500/020 Rev. 2), Unit 1 The NRC mandated the implementation of common mode failure protection for the reactor protection to reduce the risk of an anticipated transient without scram event to an acceptable level (10 CFR 50.62).

An ATWS is a postulated accident sequence initiated by a loss of feedwater, loss of offsite power, or some other design basis expected transient coincident with a failure of the RPS to shut down the reacto The ATWS Rule requires specific improvements in the design and operation of nuclear plants to mitigate the consequences of and to reduce the probability of failure to shut down the reactor following an ATWS even The NRC accepted the principle of using one of three proposed functional designs to detect the onset of ATW Surry chose using the steam generator narrow range level as the detection variabl The inspectors reviewed the NRR safety evaluation of the licensee submittal for compliance with the ATWS Rule for Surry, dated May 26, 198 The NRR staff concluded that, pending final resolution of a TS issue.by NRR, the ATWS design proposed for Surry is in compliance with the 10 CFR 50.62 requirement The inspectors observed the following regarding the AMSAC system:

Craft were using correct design change package, DC-87-26-1, ATWS Mitigation System Modification (AMSAC)

Surry/Unit 1, dated December 5, 198 A review of some areas of the design package revealed proper QC sign signoffs.

Noted that the main control cabinet was installed in the proper locatio __

A sample of drawings revealed that latest revisions were being use Craft were observed pulling three cables through a fire barrier penetration into the main control roo A QC inspector was observing the operatio Craft were observed attaching lugs to several wires leading into the AMSAC main control pane The craft were using a calibrated crimping tool, the correct size lugs, and the latest drawing..

No discrepancies were noted during these observation The inspectors al so. noted that the licensee conducted a preliminary wa l kdown of the instrument PT. that would be used for the AMSAC syste This procedure, l-IPM-RP-AMSAC-002, AMSAC Calibration, had not been approved/or issued~

The system still needs to have a number of cables terminated and a number of tests performed before being placed in servic This activity will be moni.tored again during the next inspection perio Within the.areas inspected, no violations were identifie.

Exit Interview The inspection scope and results were summarized on October 30, 1990, with those individuals identified by an asterisk in paragraph The following summary of inspectio*n activity was discussed by the inspectors during this exi In the area of operations, a weakness was identified involving the administrative process for involvement of engineering support in de\\er-mining the operability of safety-related equipmen In the area of $Urveillance, one weakness and two strengths were identifie The weakness involved not providing adequate attention to* a*

quality assurance assessment conclus.ion in the area of -safety valve setpoint testin A strength involved the licensee's voluntary action to.

upgrade its safety and relief valve setpoint progra The second strength involved improvements in the performance of emergency bus load sequence testin In. the area of engineering/technical support, a weakness was identified with regards to a 1 ack of incorporation of VPAP-0804 requirements into l-PT-1 One inspector followup item was identified on licensee corrective action*

and testing for deficiencies identified during RSHX SW flow testing (280,281/90-30-0l).

• Licensee management was informed of the items closed in paragraphs 6 and The licensee acknowledged the inspection conclusions with no dissenting comment The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspectio.

Index of Acronyms amd Initialisms AFW AMSAC ASME AP ATWS ccw CLS CFR CR EOG ESF ERF ESW EWR GPM HX I&C IST LER LCO MCR MOV MSRC MUX NCV NRC NRR NOUE PT QA QC RCS RHR RSHX RPS RWP SNSOC SW TS VPAP AUXILIARY FEEDWATER ATWS MITIGATION SYSTEM ACTUATION CIRCUIT AMERICAN SOCIETY OF MECHANICAL ENGINEERS ABNORMAL PROCEDURE ANTICIPATED TRANSIENT WITHOUT SCRAM COMPONENT COOLING WATER CONSEQUENCE LIMITING SAFEGUARD CODE OF FEDERAL REGULATIONS CONTROL ROOM EMERGENCY DIESEL GENERATOR ENGINEERED SAFETY FEATURE*

EMERGENCY RESPONSE FACILITY EMERGENCY SERVICE WATER ENGINEERING WORK REQUEST GALLONS PER MINUTE HEAT EXCHANGER INSTRUMENTATION AND CONTROLS INSERVICE TESTING LICENSEE EVENT REPORT LIMITING CONDITIONS FOR OPERATION MAIN CONTROL ROOM MOTOR OPERATED VALVE

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MANAGEMENT SAFETY REVIEW COMMITTEE MULTIPLEKER NON-CITED VIOLATION NUCLEAR REGULATORY COMMISSION NUCLEAR REACTOR REGULATION NOTIFICATION OF UNUSUAL EVENT PERIODIC TEST

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QUALITY ASSURANCE

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QUALITY CONTROL REACTOR COOLANT SYSTEM RESIDUAL HEAT REMOVAL RECIRCULATION SPRAY HEAT EXCHANGER REACTOR PROTECTION SYSTEM RADIATION WORK PERMIT STATION NUCLEAR SAFETY AND OPERATING COMMITTEE SERVICE WATER TECHNICAL SPECIFICATIONS VIRGINIA POWER ADMINISTRATIVE PROCEDURES

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