IR 05000324/1989012
| ML20247D826 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/14/1989 |
| From: | Levis W, David Nelson, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20247D789 | List: |
| References | |
| 50-324-89-12, 50-325-89-12, NUDOCS 8907250313 | |
| Download: ML20247D826 (20) | |
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i k A** ,*,/ l l l' Report Nos. S0-325/89-12'and 50-324/89-12-l Licensee: Carolina. Power and Light Company l P. 0. Box.1551 1 l Raleigh, NC_27602 Docket Nos.: 50-325 and 50-324 License'Nos.: DPR-71 and DPR-62 l /acility Name: Brunswick 1 and 2.
l Inspection Conducted: May 16 - June 21, 1989 l , Inspectors: [d ,MM M ~ 7//Y89 W. H. Ruland g r Date Signed W F % -,n ] l/$ h ,
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7//Yd69 ' W. Levis f~f Da'te Mghed l'
/WW Vm -rs//8 'D. J. N lson / f,7 7//'//89 D(te Signed
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l Approved By: ! /7/ M
~ 7/d/80-ppti.C.Danfe,SectionChief Date Sig'ned Division of Reactor Projects SUMMARY Scope:
This routine safety inspection by~ the resident inspector-involved the areas of ~ maintenance observation, surveillance observation, operational safety verification, in office Licene a Event Reports review, followup of onsite events - Unit 2, 1A Core Sproy pump failure, loss of off-site. power - Unit 2.- and action on previous inspection findings.- Results: l In the areas inspected, no violations or deviations were identified.
An inadvertent ECCS actuation occurred on Unit 2 during testing, which started all fout diesel generators and all low pressure ECCS pumps. An instrument'not under test' had failed with no readily observable symptom. Operator action during the event was appropriate, paragraph 6.a.
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An RHR service water heat exchanger and low pressure coolant injection division was rendered inoperable when a rubber gasket in' the service water system failed. The leak put two feet of water in the RHR room. Operations failed to adequately monitor the water removal, allowing additional equipment to.get we The design of the sump pump system hampered water removal.. Operations failed to adequately monitor plant pressure during~ recovery. A.similar gasket failure had occurred in 1987 on the other division, paragraph The 1A Core Spray motor-windings were damaged through contact with an internal j ventilation deflector plat All other similiar notors on Unit 1 have subsequently passed insulation check Additionally, while removing the motor for repair, the licensee may have used an overicaded forklift near safety-related equipment, paragraph Unit 2 lost off-site power while troubleshooting a ground on the Startup Auxiliary Transformer. The operator manually scrammed the reactor as per procedure. The licensee declared an Unusual Cvent and activated the Technical Support Center. All Unit 2 saftey equipment functioned as designed. Updates to the off-site agencies from the control room were not satisfactory. Overall licensee response to the event was appropriate, paragraph Significant licensee resources were used in . dealing with service w6ter operability issues. The issues included header cross-tie leakage, alternate-line-up, heat exchn ser design bases, current operational-liraitations, motor insulation life, motor thrust bearing concerns, and nadification of the reactor building closed cooling water heat exchanger inlet valves. The licensee's actions on these issues were appropriate and extensive', paragraph l
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I REPORT DETAILS l 1 Persor.s Contacted
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Licensee Employees K. Altman, Engineering Supervisor W. Biggs, Engineering Supervisor j F. Blackmon, Manager - Operations ; S. Callis, On-Site Licensing Engineer { T. Cantebury, Mechanical Maintenance Supervisor (Unit 1)
*G. Chertham, Manager - Environmental & Radiation Control M. Ciemr.icki, Security R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2) *K. Enzor, Director - Regulatory Compliance "J. Harness, General Manager - Brunswick Nuclear Project W. Hatcher, Supervisor - Security A. Hegler, Supervisor - Radwaste/ Fire Protection *R. Helme, Manager - Technical Support J. Holder, Manager - Outages *L. Jonas, Director - Quality Assurance (QA)/ Quality Control (QC) *M. Jc.. s, Director - On-Site Nuclear Safety - BSEP R. Kitchen, Mechenical Maintenance Supervisar (Unit 2)
J. O'Sullivan, Manager - Training B. Parks, Engineering Supervisor M. Pastva, Senior Specialist
*R. Poulk, Project Specialist *E. Scharff, Engineer, Operations J. Simon, Engineer, Operations W. Simpson, Manager - Site Planning and Control J. Smith, Director - Administrative Support S. Smith, I&C/ Electrical Maintenance Supervisor (Unit 1)
R. Starkey, Project Manager - Brunswick Nuclear Project
*R. Warden, Manager - Maintenance B. Wilson, Engineering Supervisor T. Wyllie, Manager - Engineering and Construction Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force member NRC employees *S. Long, Senior Reliability and Risk Analyst, NRR *T. Fresco, NRC Contractor, Brookhaven National Laboratories General Electric Company J. Mokri, Senior Electrical Engineer * Attended the exit interview
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1 Acronyms and initialisms used in the report are listed in paragraph 1 . Maintenance Observation (62703) J The inspcctors observed maintenance activities, interviewed personnel, and reviend records to verify that work was conducted in accordance with j approved procedures, Technical Specifications, and applicable industry ; codes and standards. The inspectors also verified that: redundant j components were operable; administrative controls were followed; tagouts
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were adequate; personnel were qualified; correct replacement parts were used; radiological controls were proper; fire protection was adequate; quality control hold points were adequate and observe'd; adequate post-maintenance testing was performed; and independent verification , requirements were implemented. The inspectors independently verified that i selected equipment was properly returned to servic Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenanc The inspectors observed / reviewed portions of the following maintenance activities: 89-ALKE1 2B-1 Battery Charger Breaker Troubleshooting 89-AMJR1 LPRM Troubleshooting i MI-10-502D Visual Inspection of Electric Motors - 2A Core Spray OPM-M502 Inspection of RHR and CS Pump Motor Surge Ring Brackets - j 2A Core Spray QBL-225 G16-C007 Reactor Building Equipment Drain Tank Pump - ; Disassembly and Inspection I SP-89-206 Removal of 1A Core Spray Pump Motor During the shutdown and cooldown of Unit 2 after the SAT failure (see ) paragraph 9), the licensee had difficulty placing the RHR "A" loop in shutdown cooling. OP-17, Revision 80, requires the operators to warm-up
- the RHR loop by bypassing the injection check valve and establishing l reverse flow through the loop from the reactor to the torus. The A loop i
was not warming up in spite of operations aligning the valves to do so.
l On June 20, 1989, after a successful LLRT on the RHR outboard injection-containment isolation valve 1-E11-F017A, the valve was cycled without any subsequent decrease in pressure downstream of the valve. This indicated that the valve disc had separated from the ste The licensee plans to visually ex .ine the disc and stem in order to determine the cause of the failure and to repair the valv The inspectors will ; continue to follow the licensee's actions next reporting perio Violations or deviations were not identifie _____ ___
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1 Surveillance Observation (61726) The inspectors observed surveillance testing - required by Technical-l Specifications. Through observation, interviews, and record review, the ! inspectors verified that: tests conformed to Technical Specification requirements; administrative controls were followed; , personnel were
. qualified; instrumentation was calibrated; and data was accurate and complete. The inspectors independently verified selected test results and -
proper return to service of equipmen The inspectors witnessed / reviewed portions of the following test-activities: IMST-ApRM11W APRM Channel A, C & E Channel Functional Test 2MST-RCIC15M RCIC Steam Leak Detection Channel Functional Test 2MST. ors 24M RPS Reactor Vessel Low Water Level (LL1) Trip Unit Channel ' Calibration Violations or deviations were not identifie . Operational Safety Verification (71707) The inspectors verified that Unit 1 and Unit 2 were operated-in compliance with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records, and independent verification of safety system statu The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met. Control operator, shift supervisor, clearance, STA, daily and standing instructions, and jumper / bypass logs were reviewed to obtain information concerning-operating trends and out of service safety systems to ensure that there-were no conflicts with Technical Specification Limiting Conditions for Operations. Direct observations were conducted of contro) . room panels, instrumentation and recorder traces important to safety in order to verify operability and that operating parameters were within Technical Specification limits. The inspectors observed shift turnovers to verify that continuity of system status was maintaine e inspectors verified the status of selected control room annunciator Operability of a selected Engineered Safety Feature division was verified weekly by ensuring that: each accessible valve in the flow path was in-its correct position; each power supply and breaker was closed for components that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the value operator; there was no leakage of major components; there was proper - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ - _ _ - - _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ . _ _ _ _ _ -_- ______________A
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lubrication and cooling water 'available; and a condition did not exis which might prevent fulfillment of-the system's functional requirement Instrumentation essential to system actuation or performance was verified ' operable by observing. on-scale indication and: proper instrument ~ valve-lineup, if accessibl .The inspectors verified that. the licensees health physics policies / procedures ' were followe This included observation of HP practices and a review of area surveys, radiation work permits, postings, and instrument calibratio The inspectors verified that: ~ the security organization was properly manned and security personnel. were capable of performing their assigned functions; persons and packages were: checked prior to entry.into the PA; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo, identification badges;. personnel in vital areas were authorized; and effective compensatory measures were-employed when require The inspectors also observed plant housekeeping controls, verifie'd position of certain containment isolation valves,. checked a clearance,-and verified the operability of onsite and offsite emergency , power source Violations or deviations were not identifie . In Office Licensee Event Report Review (90712) The below listed LERs were reviewed to verify that the information provided met - NRC reporting requirement The~ verification included adequacy of event description and corrective action taken or planned, existance of potential generic problems, and the relative safety significance of the even UNIT 1 ! l (Closed) LER 1-89-07, Unplanned Auto Start of Standby Gas ireatment
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System Trains During Action to Change Boundary of Equipment Clearance on Reactor Building Ventilation Dampers.- <
(Closed) LER 1-89-09, Failure to Establish a Fire Watch as Per Technical
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(Closed) LER 1-89-10, Auto Isolation of Units 1 and 2 Common Control ;
Building lleating, Ventilating, Air Conditioning System and Emergency Air' , j Filtration System Due to Chlorinated Water Leakag UNIT 2 (Closed) LER 2-89-02, HPCI Declared Inoperable Due to Cracked Welds o ' Two Support i Violations or deviations were not identified.-
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' Followup of Onsite Events - Unit 2 (93702) ECCS Actuation On. June 5,1989, with Unit 2 at 100% power, an inadvertent LOCA'
signal was initiated which resulted in all four ; standby emergency diesel generators automatically starting, drywell cooling' fans securing, and Division I and II core spray and LPCI pumps automatically starting: The diesels'did not load since power was'no lost.'to the emergency buses. The ECCS pumps operated on minimum flow and did not inject water to the reactor vessel since their low-pressure permissive was not satisfie The inspector was present in the control room and verified the operator's actions were appropriate. After verifying that a valid LOCA signal did not exist, the ECCS pumps were secured in their manual override stop position. . Extra personnel were stationed t monitor plant parameters and all alarms received. Any abnormal' plant conditions were recorded to aid in determining the caus'e of the initiation signa The E0Ps' were entered briefly when the average primary containment temperature reached 135 degrees F. When the - cause of the trip was determined, the signal was reset and systems were returned to norma The licensee determined that the cause of the trip was a. failure of one trip unit instrument associated with the LOCA low level signal _ while its companion trip unit ras being tested. The failure cppears-to be related to the failure of the output transistors on 'the Rosemount Model 510 trip unit. This type .of failure would not be recognized by operations or I&C personnel in. the normal performance of their dutie The licensee experienced a similar type event as reported in LER 2-89-01 when HPCI received an inadvertent actuation signal Initial licensee research revealed that at least one other utility has experienced similar type' problems with the' output-transistor of the Rosemount Model 510 trip units'. The licensee is continuing their investigation which includes bench ' testing and discussions with Rosemount and other utilities. The inspector will review these items, including the licensee's 10 CFR ' Part 21' assessment., when the LER is issue RHP Service Water Gasket Failure
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While aligning Unit 2 B loop RHR for shutdown cooling,- a gasket failed on the upstream side of the 2-E11-F014B valve, a manual valve which is the service water inlet valve to the' B RHR heat exchange The failure occurred at 6:30 a.m., on June 19, 1989, with Unit 2 in operational condition Upon report of the failed gasket, the - operators secured the RHR service water booster pump, shut the isolation valves to the heat exchanger and secured other electrical - _ _ _ - _ - -
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i equipment located in the vicinity of the lea The leak slowed to approximately 15 gpm with the pump secured and the isolation valves shut. Several thousand gallons of water was' spilled from the 20 foot elevation where the valve is located, filling the -17 foot elevation (south RHR room) with about 2 feet of water. The licensee inspected the wetted equipment and declared the affected equipment inoperabl The following observations were noted concerning this event:
(1) previous Gasket Failures Gasket failures have occurred in the past in the service water system, as documented in inspection reports 88-24 and 87-4 This gasket # ailure will be included with those identified in URI 324/87-43-06. Further inspection will be done on this item concerning the licensee's root cause assessment and adequacy of their corrective actions to determine if enforcement action is warrante (2) Recovery Operations While witnessing recovery actions, which included the pumping of water from the south RHR room with a submersible pump, the inspector observed that the submersible pump was spraying water on both CRD pump motors and the RCIC instrumentation rack. This equipment had been previously inspected and determined to be satisfactory since it was not sprayed during the initial event and was not submerge Subsequent to the inspector's observation and notification of operations personnel, a new submersible pump was supplied and the affected wetted equipment inspecte The licensee was using the submersible pump to pump water directly to the salt water release tank which is located outside of secondary containmen To accomplish this, a hose had to be run through the 20 foot Reactor Building airlock doors which normally maintain secondary containment. Since the plant was in operational condition 3, this put the plant in an ACTION l
statement which required restoration of secondary containment within 8 hours or be in cold shutdown within the next 24 hour These actions were necessary because the present ccofiguration of the Reactor Building sump collection system does not allow the pumping of salt water to radioactive wast The licensee had plans to correct this deficiency, but apparently the modification that would allow the pumping of Reactor Building sump directly to the salt water release tank was deferred due to budgetary concern _ ._ _ _ _ - -
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7 ) l (3) Operator Actions At approximately 8:25 a.m., the inspector observed that reactor pressure was greater than 113 psig and that HPCI and RCIC were , not lined up in their normal standby lineup as require ! Pressure had increased to greater than 123 psig at approximately l 8:00 a.m. Both systems had isolated when reactor pressure had been reduced to less than their -low pressure isolation trip setpoint Subsequent to the pressure reduction, the inboard MSlYs were closed to allow the reactor water to heat up to j promote natural circulation to correct thermal stratification in
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the reactor vessel. The operators had not taken any action to re-align HPCI/RCIC after pressure had increased to greater than 113 psi i i The inspec+0r questioned the SF concerning the status of these systems. The SF stated that he had just recognized that the-pressure requirements had been exceeded for HPCI and RCIC to be operable and that he had given direction to the C0 to line up RCIC for automatic initiation. He further stated that HPCI would not require realigning since, upon an automatic initiation signal, the appropriate valves would automatically align to j their required positio The inspector pointed out to the SF that a caution tag on the 2-E41-F003, the outboard steam supply valve, stated that the HPCI system was to be declared inoperable i anytime the valve was sh t, since recent design analysis showed that the valve motor may nct develop sufficient torque to open , the valve under all design t. asis accident conditions The SF i recognized his' error and directed that HPCI also be lined up in the normal standby lineup. Based on actual plant conditions at the time (ie., plant pressure remaining below 200 pounds), the inspector believes that HPCI would have performed its function , since the actual differential pressure across the F003 valve was ! much less than the design condition Also, no TS ACTION-statement time limit was exceede (4) Conclusions This event demonstrated several weaknesse The _ operations ; staff failed to adequately control the cleanup effort in the -17 foot level of the south RHR room. There is an apparent design deficiency in the Reactor Building sump collection and disposal system for salt wate The operations staff failed to i adequately monitor key plant parameters. These weaknesses were i discussed with licensee management; the inspector's comments were acknowledge Violations or deviations were not identifie _ _ - - _ _ - _ _ _ -
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8 1 q j lACoreSprayPumpFailure(c703) On June 4, 1989, fire suppression sprinklers were. inadvertently discharged in. the Unit 1 north core spray room which contains the pump, piping, .and : instrumentation for the 1A core spray system. Virtually all equipment on -{ the -17 foot level was wette Unit I was operating at full power.at th ? tim The licensee' declared 1A core spray IN0PERABLE at 5:42-a.m. This- ! placed Unit 1 in a 7 day LC0 in accordance with TS.- A damage assessment of wetted equipment revealed zero resistance to= ground on the.1A core spray pump motor presumably caused by the' water. The . licensee took' action to dry out the motor. This included forced-ventilation;through the motor housing and providing dc from'a welding machine:to the motor winding .J After several days, resistance readings had improved only. slightly. . The _l licensee' determined that motor disassembly and overhaul was required. The ! motor was to be transported off site for this work. Because a spare motor was not available, it was apparent that Unit;I would have to shut down due to TS time evnstraints. The licensee began sotor. removal on June.9. 1989,. prior to the shutdow l The removal involved lifting the motor from the -17 foot elevation in the north core spray room vertically through.a hatch to' the Reactor Building
+20 foot level. From there it would be transported the length of the Reactor Building in a' nearly straight path to the large roll-up doors on i the east side where it could be loaded on a. truck. This path included 1 close passage by the control rods' hydraulic control units. .The licensee 1 evaluated the safe load path with respect to safe shutdown equipment as committed to in FSAR section 9. The inspector observed the handling operation from the point of the motor reaching the 20 -foot Reactor i Building floo I The motor was placed on rollers, remaining in a vertical po(Ition, and rolled to where it could be loaded on a fork lift.- This-loading was ;
accomplished with some difficulty, prompting the inspector to question the- .. capacity of the fork lif The inspector observed .one 'of the . fork - 11 ft's - rear wheels raise off the floor momentarily- as'the motor was lifted. The inspector was told by. the foreman that' the fork lift capacity was - approximately 8400 pounds and the motor weight was approximately 8000 pound Af ter the-motor was propely secured, it ' appeared that the fork: lift was at or near capacity, but capableof safely transporting the - motor. The motor was successfully moved:to.the roll up doors where it was unloaded from the fork lift by the Reactor Building crane, Subsequently, the inspector determined that the assumed weight of the motor was. 8400 pounds and the fcrk lift. . capacity was 8000 = pounds'. Therefore, 'the fork lif t was apparently overloaded. The licensee stated that the actual motor weight could be from 6800 pounds. to 8400 pounds.~ The' licensee further stated that the foreman on the job made a judgement-that the motor removed fromwasthe within motorthe capacity prior of the forkilift to lifting-(i. becausebox, oil, terminal of weig)ht etc. . The licensee intends to weigh the motor upon its return to the site .to-determine ~if the fork lift was actually overloade i
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In accordance with the FSAF commitment mentioned above, the licensee generated special procedure SP-89-206, Removal of 1A Core Spray Pump Motor, to provide guidance and instruction to assure safe removal. This procedure requires. that transport devices be rated for the motor weight and cautions that "If the motor is transported in the vertical position, it will be very unstable."
Transporting heavy loads in the proximity of safety related equipment with the reactor at power warrants proper control and oversite. The licensee stated that the foreman on- the job should have requested assistance to evaluate the use of the fork lift, but defended the eventual outcom The motor was transported to a vendor for repair, where it was determined , that the low resistance to ground was not caused by the motor being wetted ! with water. Upon disassembly, the lower stator coil end turns were found d in contact with an air deflector plate. Vibration during motor operation caused fretting of the coil insulation which gradually wore away. There was evidence of arcing at the points of contact. The coil end turns were contacting the deflector plate approximately 270 degrees around the circumference of the motor. Additionally, putty between the coils was i cracked with some pieces missing. The end turns-to-deflector contact appeared to be caused by axial misalignment of the stator coils. How and when this occurred is still being analyzed by the licensee and vendo The licensee's technical support staff had suspected that the motor failure was not water related and had recommended testing the other core spray pump motor and the four Unit 1 RHR pump motors which are of a similar desig With discovery of the actual failure cause, hi-pot testing was performed with satisfactory results on the Unit 1 RHR pump
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motors and the IB CS pump moto Routine resistance checks performed on an approximate annual basis on the failed motor did not reveal degradation of the coil insulatio The rasistance values for the last three checks were 150 Meg-ohm,1,000 Meg-ohm, and 50 Meg-oh The 50 Meg-ohm value was obtained in June 198 The licensee considers values in excess of 5 Meg-ohm to be acceptabl The inspector will monitor the investigations involved with this event, specifically:
- Outcome of an investigation report concerning fire sprinkler actuation Results of weighing the core spray moto Outcome of motor failure analysi f i
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These issues will. be tracked as an Unresolved Item * pending their resolution: 1A Core Spray Pump Motor Failure, (325/89-12-01).
Violations or deviations were not identifie . Loss of Off-Site Power - Unit 2 (93702) On June 17,1989, at 8:57 p.m., the licensee delcared an Unusual Event after Unit 2 was manually scrammed following a loss of off-site powe < Earlier, at about 4:00 p.m.. an annunciator in the control room-indicated that there was a gtcand on the SAT and the licensee's relay crew (non-plant personnel) was called out to troubleshoot. They initially thought that there was a problem with the neutral transformer connected to the SAT. When the relay crew tried to jumper the primary of the neutral transformer at 8:47 p.m., the connecting wire to the SAT vaporized and several panels of ductwork for the SAT buswork ruptured, dumping gallons of water that had accumulated in the ductwork. Nobody was injure The contol operator manually scrammed the reactor from 72% power when the q The main steam
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loss of the SAT tripped both recirculation pump isolation valves shut when the unit was tripped and UAT power was lost, as designed. All safety equipment on Unit 2 functioned as designed. Safety relief valves lifted automatically and operators manually opened relief valves as necessary to initially contol prescure. HPCI and RCIC were used to maintain level while HPCI was used for pressure control later in the event. All four diesel generators started with diesel generators 3 and 4 supplying power to emergency buses E-3 and E-4. Diesel generators 1 and 2 did not load since the Unit 1 SAT was still suppying power to E-1 and E- The licensee disconnected the Unit 2 main generator and energized the UAT from off-site power at 3:30 a.m., on June 18, 1989. The licensee had some trouble clearing the diesel generator start signal, since the under voltage relay for the SAT had not re-energize Once the licensee manually relatched the relay, off-site power from the VAT was paralleled with DG 3 and 4 and all the emergency diesels were secured by 6:21 The Unusual Event was terminated at 6:26 The licensee declared an Unusual Event In accordance with the site Emergency Plan. However, following the initial notifications to state, county and coast guard at 9:10 p.m., the licensee did not make followup notifications until 11:15 p.m., after the TSC was activate Inadequate folicwup notifications from the control room has been an issue in past Emergency Drills. Once communicator responsibilities were shifted to the TSC, frequent updates to local authorities were made. The licensee is taking action to require updates at least hourly. This information is being referred to the Region II Emergency Preparedness section.
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As stated above, due to the anticipated long duration of the event, the l licensee activated the TSC and OSC at 10:55 p.m. This enhanced the ' licensee's ability to maintain good centralized control of the even The , NRC Operations Center requested continuous communication via the Emergency Notification System. The licensee provided thorough, updated information
- every 30 minutes to the Region II Incident Response Center which was l manned, but not activate The resident inspector participated as NRC i
site team leader in the TSC.
l Preliminary licensee investigation revealed that the SAT failure was probably caused by personnel error combined with the ductwork not working as designed. The SAT ductwork had a 1-inch diameter hole that allowed water to enter, and since at least two ductwork drains were plugged, the water . collected in the duct. In conjunction with this, when the relay crew bypassed the neutral transformer, its function of limiting the , current to ground was defeated, t The licensee and INP0 established an investigative team to further review l the event. Further inspector followup will be done on the results of that l review and of the LER which is to be issue Violations or deviations were not identifie . Action on Previous Inspection Findings (92701) (71707)
(Closed) Unresolved Item 325/88-38-04 and 324/88-38-04, Water Contamination of HPCI Turbine Oil. This item was inspected by the maintenance team during their inspection as documented in repart 89-0 The team classified this issue as a violation, 325,324/89-0101, for failure to take timely and adequate corrective actio (0 pen) Unresolved Item 325/89-09-01 and 324/89-09-01, Service Water System Design Deficiencies. The licensee continues to review, evaluate and modify both units' service water systems to resolve the design issues
! raised during the Diagnostic Evaluation Team review. Attached to this report is a simplified diagram of the BSEP SW system, and the current status of the SW issues are addressed below: Unit 1 Nuclear to Conventional Header Cross Leakage The licensee performed the cross tie leakage test and found the leakage to be about half of that in Unit Therefore, the analysis justifying operation of Unit 2 bounds the Unit 1 case, since cross leakage reduces the flow to the safety related component SW Alternate Lineup
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As an interim action, the 1.icensee evaluated and approved operation of the service _ water systems by: i
- Transfer of the RBCCW' heat exchanger from the nuclear SW header to the conventional . SW header by. closing valve . SW-V106 and '
opening valve SW-V14 Continuously operate RHR-SW A loop from the nuclear SW header at 3500 to 4000 gpm by opening valves SW-V102 and SW-V10 .
- Continuously. operate the ECCS room coolers from the nuclear SW -
header by cpening valve SW-V11 This alternate lineup'was already addressed in; operating procedure l The licensee's EER 89-0163, Revision 1, dated June 13. .1989, permitted operation 'of the system as stated' above, with a limit of 87 F on SW inlet temperature. ' A single failure analysis and hydraulic review was performed as ' part of the evaluation. The inspector reviewed selected portions of the EER and concluded that , the alternate lineup was appropriat l RHR Heat Exchanger Design Basis The licensee concluded that the minimum SW operating conditions for-the RHR heat exchangers to perfonn their design function was RHR SW flow greater than or equal to 4500 gpm with a service ' water-temperature less than or equal to: 90 F. The inspector reviewed the licensee's EER 89-0166, dated June 9, 1989,.which documented their review findings. The licensee addressed the followi,ng factors:
- FSAR worst case, LOCA analysis, Case D .in Table 6.2.1-8. This case assumes only 1 SW pump,1 RHR SW pump,1 RHR pump with worst case LOCA nunbers from the FSAR. . - Heat Exchanger heat transfer performanc ,
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Service Water heat exchanger outlet' temperature effect on piping and pipe suppcrt Suppression pool temperature limits imposed by the Mark - .I 4 Containment Long Te'rm Progra Required Net Positive Suction Head for Core Spray and RHR pump .j l
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Response to small break LOCA j
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Review of pending Technical Specification-change that specifies l maximum internal torus temperature of 200"F (request to change ' to 220 F) in the Design Features, section S. . Environmental Qualification profile.
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Thus, the licensee determined that containment cooling would be I assurred with the above factors considered, the service water ) parameters as indicated, and an RHR flow of 7500 gp j The licensee found that Case D in the FSAR analysis took. credit for containment pressurization in determining adequate NPSH for the ECCS pump Regulatory Guide 1.1 does not allow credit for containment pressurization for NPSH calculations for ECCS pumps. The assumptions I made in the licensee's current analysis versus those in the FSAR are shown below: Licensee's ] Parameter Analysis FSAR ! l
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SW flow to RHR (gpm) 4500 4000 SW inlet temperature 90 95 to RHR (degrees F) l RHR flow (gpm) 7500 7700
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RHR inlet temperature 193.3 (peak calculated) 210.4 (peak)
(degrees F) ;
Initial Suppression Pool 95 90 temperature (degrees F) Initial power level (%) 102 10 Credit is taken in the licensee's analysis for the additional blowdown mass _ deposited in the drywell/ suppression pool, where as the FSAR does no ,
The inspectors reviewed portions of the licensee's EER and their I conclusions, and took no exception to their conclusions for current RHR HX performance at this time. The inspectors will continue to review this issue, especially the Regulatory Guide 1.1 issu Current Operational Limitations ; The licensee revised EER 89-135, June 12, 1989, to take credit for the above RHR heat exchanger performance. This revision increased the limitation on service water inlet temperature to 87 F with a limit on RBCCW SW flow of 4500 gp The core spray room cooler required flow is now the limiting flow rat SW Pump Motor Insulation Life The licensee evaluated the operability of the SW pump motors after the 2B nuclear SW pump motor failed. The 2B nuclear SW pump motor insulation was damaged and a stator winding shorted to ground while the motor was running near design conditions. As documented in EER-89-0169, dated May 31, 1989, the licensee concluded that short term operability of the motors was assured, l _ _ - -
.. * . . .
The central issue involves the remaining life of the installed motor Using motor winding temperature taken on May 13 and 14, 1989, conservative estimates of motor run time, and accepted industry methodology, the licensee icund that four motors had exceeded their calculated thermal lif These motors are now on the 2A, 2C, and 1C s conventional SW pumps and the 2A nuclear SW pump. To assure short term operability, the licensee satisfactorily performed an insulation overvoltage test on GE's calculated worst case motor, the 2C conventional 3 moto That motor had estimated run hours (123 000) 1 that were almost five times greater than predicted thermal life !
(26 000). The licensee, per GE's recommendation, tested the ground :
wall insulation at 10 200 Vdc and the turn-to-turn insulation test l using an 8000 volt surg Other corrective actions implemented by the licensee include:
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Swapped two motors to enhance overall reliabilit Expedited rewind and changeout of four motors that have exceeded their calculated thermal lif i
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Directed operations to minimize operation of the motors with the greatest thermal ag Review and approve GE's internal motor ventilation improvement j
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Will establish a motor monitoring progra Installed temporary ventilation skirts around motor to separate intake and exhaust ai The inspector interviewed plant personnel, including the vendor technical representative, performed a detailed review of the EER, and examined plant equipment related to this issue. The inspector found the licensee's actions to be extensive and appropriat SW Pump Motor Thrust Bearing An additional issue was identified concerning the motor thrust bearing At low flow rates, the licensee with their vendor found that excessive thrust may be applied to the thrust bearing, damaging the bearin The licensee is currently operating both units' SW systems with the RHR room coolers in service to establish some minimum flow through the pump The pump vendor shop tested a pump and motor configuration to determine a discharge pressure versus thrust curve and pump NPSH requirements. The data will be used to establish , permanent minimum flow requirements for the pum A final document on this issue had not been issued by the vendor or licensee at the ' end of this reporting perio _ _ _ _ _ . _ -
"
N ', A ! 1 ] The inspector discussed this issue..with NED personnel and has no immediate concerns regardiig ' operability since a minimum flow path has. been established that appears acceptable. in. light of. the draft
.
data. Tlie inspectors will review the licensee's' continued work in
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this area during future inspections, specifically, the documentation _j, of the testing and engineering evaluatio * RBCCW HX Inlet Valves One significant problem with the-current -SW design is that a' single failure of. the-V106 valve (see. attachment) will divert flow to the; 4 non-safety RBCCW heat 'exchanger The licensee has a , plant 1 modification in progress on 'both units to add a motor operator.and { necessary logic and controls for the redundant V103 valve. Further,
'
the licensee will determine if V103-and V106 should short stroke to maintain a minimum flow through the SW pump The inspector's review of the SW system will continue until the issues l are fully resolve (0 pen).IFI 325/84-31-01 and 324/84-31-01, Licensee to Develop and Submit . a Technical Specification Change Request for Rod Sequence Control System I Testing. This item was previously inspected in -report 325/87-31 and 1 324/87-35. The licensee has. installed the new RWSi in both units and has recently received Technical Specification Amendments 127 and'157 for Units 1 and 2, respectively, which require the use of Banked Position Withdrawal Sequence as the RWM control rod program instead of' the group notch withdrawal sequence, The development of the Technical Specification ; change request for the removal of RSCS is currently in progres J (Closed) IFI 325/86-11-04 and 324/86-u.-04, Poor. Quality RRIL Procedure The inspector reviewed the licensee's current schedule forJ upgrading maintenance instructions and procedures which-includes the RRIL procedur project. The Maintenance Instruction upgrade project is scheduled to be completed in January 199 Priority for upgrade is being placed on procedures most frequently used. This item is closed-on the basis that the project is established with a schedule and prioritization in plac . The inspector will continue to monitor the progress.of the program. This ! item was also addressed in Inspection Report 325, 324/88-2 ) i (Closed) IFI 325/86-24-03 and 324/86-25-03, Review of .t.onergan Relief' Valv This item had been previously inspected in report.325,324/88-2 The licensee has ordered and received replacement parts for the valves which will not be subject to previously identified corrosion problem The valves will be rebuilt or replaced on an as needed basis as determined by the licensee's IST program. The valves are currently on a 5 year test and inspection schedul Violations or deviations were not identifie i a L- -- . . _ _ - -
_,
' % . 'W
10. Exit Interview (30703) i The inspection scope and findings were' summarized on June 21, 1989, with those persons indicated in paragraph 1. . The inspectors described the areas inspected and discussed in detail .the inspection findings listed below and : those. addressed 'in the Results section of this repor Dissenting comments were not' received from the . licensee. . Proprietary information is not contained in this. repor . Item Number- description / Reference Paragraph 325/89-12-01 URI - 1A. Core Spray Pump Motor Failure
"
(paragraph 7).
. 11. Acronyms and Initialisms j
A0 Auxiliary Operator 4 APRM Average Power Range Monitor , BSEP Brunswick Steam Electric Plant i C0 Control Operator CRD Control Rod Drive ! CS Core Spray dc direct current DG Diesel Generator ECCS Emergency Core Cooling System
'
EER Engineering Evaluation Report E0P Emergency Operating Procedure ESF Engineered Safety Feature F Fahrenheit- ! FSAR Final Safety Analysis Report GE General Electric GPM Gallons Per Minute i HP Health Physics .
<
HPCI High Pressure Coolant Injection ' HX Heat Exchanger I&C Instrumentation and Control IFI Inspector Followup Item INP0 Institute of Nuclear Power Operations'
.IPBS Integrated Planning, Budgeting and Schedulirig '
IST In-Service. Testing LC0 Limiting Condition for Operation Licensee Event Report
' '
, tER ! LLRT Local. Leak Rate Test LOCA Loss of Coolant Accident LPCI Low Pressure Coolant Injection LPRM . Local Power Range Monitor MSIV Main Steam Isolation Valve NED Nuclear Engineering Dep NPSH Net Positive Suction Head _ _ _ _ _ _ - _ _ - _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ .
__ ___ i
'* ,. .
:
i NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation OP Operating Procedure OSC Operations Support Center PA Protected Area PNSC Plant Nuclear Safety Committee PSIG Pounds per Square Inch Gauge QA Quality Assurance QC Quality Control RBCCW Reactor Building Closed Cooling Wate-RCIC Reactor Core Isolation Cooling , l RHR Residual Heat Removal ' RPS Reactor Protection System RRIL Regulatory Related Instrument List RSCS Rod Sequence Control System RWM Rod Worth Minimizer SAT Startup Auxiliary Transformer SF Shift Foreman SP Special Procedure STA Shift Technical Advisor ,
'
SW Service Water TS Technical Specification TSC Technical Support Center UAT Unit Auxiliary Transformer i URI Unresolved Item Vdc Volts Direct Current ' i i
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