IR 05000280/1995017
| ML18153A667 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/02/1995 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A666 | List: |
| References | |
| 50-280-95-17, 50-281-95-17, NUDOCS 9511160022 | |
| Download: ML18153A667 (20) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report Nos.:
50-280/95-17 and 50-281/95-17 licensee:
Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:
50-280 and 50-281 License Nos.:
DPR-32 and DPR-37 Facility Name:
Surry I and 2 Inspection Conducted:
September 3 through October 14, 1995 lead Inspector: })G
.
,
.
M. w.PB~~~~'~r Res~(lnspector Other Inspectors:
D. M. Kern, Resident Inspector W. K. Poertner, Resident Inspector L. R. Moore, Region II L. W. Garner, Region I, Project Engineer Approved by:
s-Scope:
f Reactor Projects Branch 5 Division of Reactor Projects SUMMARY IJ /o-z_/f<
D a t'e Si g ri ea----'
This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance and surveillance inspections, engineering review, plant support, balance of plant review, deviation report review, and action on previous inspection item Inspections of backshift and weekend activities were conducted.
9511160022 951103 PDR ADDCK 05000280 Q
Results:
Plant Operations Control room operators exhibited good command and control and properly implemented abnormal procedures during the September 29 power loss to the IH and 2J emergency buses (paragraph 3.3).
Operations' identification and pursuit of resolution of a suspected Reactor Coolant System leak associated with pressurizer level tap piping, demonstrated a good questioning attitude (paragraph 4.4).
Maintenance Station blackout testing evolutions were adequately controlled. Test performance and resolution of a test problem demonstrated good communications between operations, engineering, and maintenance organiza~~1ns (pangraph 4.2).
Maintenance personnel properly implemented several positive initiatives to improve Unit 1 Rod Control System reliabilit Root Cause Evaluation (RCE)
95-08 was thorough and established a comprehensive set of corrective actions (paragraph 4.3).
The RCE associated with the September 14, Turbine Building flooding event, performed by the 1 ine organization, represented a COi11111i ~111ent to identify and correct conditions which represented high risk for core damage (paragraph 7).
Engineering The deficiencies discovered during motor operated valve coefficient of friction testing were properly addressed (paragraph 4.1).
The IA and 2A station batteries expe1*ienced repeated low cell voltages and electrolyte stratification during the first half of 199 A subsequent RCE was comprehensiv The IA station battery was replaced during the Unit 1 refueling outag Continuing licensee actions to address battery degradation were appropriate (paragraph 6).
- REPORT DETAILS Persons Contacted Licensee Employees
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- * * * * * * * K. * * Benthall, Supervisor, Licensing Blake, Jr., Superintendent of Nuclear Site Services Blount, Superintendent of Maintenance Christian, Station Manager Costello, Station Coordinator, Emergency Preparedness Erickson, Superintendent of Radiation Protection Garber, Licensing Garner, Outage and Planning Hayes, Supervisor, Quality Assurance Hayes, Supervisor of Administrative Services Luffman, Superintendent, Security Lynch, Administrative Services McCarthy, Assistant Station Manager, Operations and Maintenance Miller, Quality Assurance Sarver, Superintendent of Operations Saunders, Vice President, Nuclear Operations Shriver, Assistant Station Manager, Nuclear Safety and Licensing Sloane, Superintendent of Outage and Planning Smith, Site Quality Assurance Manager Sowers, Superintendent of Engineering Swientoniewski, Supervisor, Station Nuclear Safety Other licensee employees contacted included plant managers and supervisors, operators,. engineers, technicians, mechanics, security force members, and office personne NRC Personnel
- M. Branch, Senior Resident Inspector D. Kern, Resident Inspector
- K. Poertner, Resident Inspector
- L. Garner, Project Engineer, Region II
- Attended Exit Interview Acronyms used throughout this report are listed in the last paragrap.
Plant Status Unit 1 was shutdown on September 8 for a scheduled 37 day RF The unit remained shutdown for the rest of the inspection perio Unit 2 operated at power for the entire perio The C RCP seal leakoff flow dropped below the recommended value during the inspection period.
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AP 9.00, RCP Abnormal Conditions, revision 6, was entered and seal flow was closely monitored during the remainder of the inspection perio Operational Safety Verification (71707)
The inspectors conducted frequent tours of the control room to verify proper staffing, operator attentiveness and adherence to approved procedure The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance with TSs and to maintain overall facility operational awarenes Instrumentation and ECCS lineups were periodically reviewed from control room ; ** ~~cations to assess operabilit Frequent plant tours were conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs and housekeepin Deviation reports were reviewed to assure that potential safety concerns were properly addressed and reporte.1 RHR Pump Throughwall Leak On September 9, at approximately 10:30 p.m., an !SI inspection identified a throughwall leak in the Unit 1 A RHR pump casin An evaluation determined that the leak was approximately one drop per minute and was located on the suction side of the pump casin At the time of discovery, the A RHR pump was inservice and the RCS was solid and pressurized to 300 psi The pump casing was inspected by an NOE engineer and an ultrasonic examination was attempted but was unsuccessful due to the leak location. A visual examination indicated that the defect was a ca~ting flaw, probably due to porosit The pump was declared inoperable at 3:30 a.m. on September 10, based on ASME Section XI criteria. However, the pump was left in service due to operator concerns with swapping RHR pumps with the RCS solid." These concerns were addressed and the pump was subsequently secured ~t 9~35 a.m., after the B RHR pump was started for decay heat remova The A RHR pump was isolated and the piping draine~ ~n determinP if adequ:te isolation could be achieved to perform repair The licensee determined that the leakage past the pump isolation valves would not support repairing the pump with the RHR system pressurize The licensee initially requested enforcement discretion from the NRC to allow entry into the refueling mode of operation with only one operable RHR pum TS requires that two RHR pumps be operaLle with the reactor head detensioned and level in the transfer canal less than 23 fee The NRC determined that the circumstances did not meet the criteria for enforcement discretio Based on discussions with NRC, the licensee submitted a relief request from ASME Section XI requirements for flaw evaluation requirement The relief request was based on an analysis that determined that the structural integrity of the pump would be maintained under design basis loading The relief request was approved by the NRC on September 12, and the licensee continued with refueling outage activities to commence core
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offloa Once the core was offloaded, repair of the A RHR pump was initiate Pump repair was completed prior to core onloa Unit 1 Loss of Inventory Event On September 14, 1995, while shutdown for refueling, the Unit 1 reactor vessel water level standpipe indication experienced an unexpected drop from approximately 18 feet to 13.3 fee The cause of the event was due to the isolation of the reactor head vent with a nitrogen bubble trapped in the hea As pressure was relieved from the top of the standpipe due to depressurizing the PRT, indicated standpipe level increase Control room operators increased the letdown rate in order to maintain standpipe level stable at 18 fee The letdown continued for approximately three and a half hours until the bubble in the reactor head expanded and reached equilibrium. Approximately eleven hours later, reactor vessel head detentioning allowed a vent path for the bubbl This caused the standpipe level to drop to 13.3 feet, the actual reactor vessel water leve RHR cooling was not losL during the even Details of this event are documented in NRC IR 50-280,
. 281/95-2 Loss of Power to Two Emergency Buses On September 29 at 8:01 a.m., power was lost to the lH and the 2J emergency buse At the time of the event, Unit 1 was in a refueling outage with the core offloaded to the spent fuel pool and Unit 2 was operating at 100 percent powe When power was*
lost, the #1 EOG and #3 EOG automatically started on bus undervoltage conditions and reenergized the 1~ and 2J emergency buses, respectively, as designe During the event, Unit 2 remained stable at 100 percent power and the Spent Fuel Pool Cooling System remained in service to remove decay hea The lH and 2J emergency bus deenergized due to breaker 15Cl openin ft~ operator opened the fuse dra~1er for the F transfer bus potential transformer which caused a simulated undervoltage condition on the F transfer bus and a trip signal to breaker 15C When breaker 15Cl tripped, power was lost to the F transfer bus and the. lH and 2J emergency buses which were being supplied from this bu Offsite power was restored to the F transfer bus at 12:57 The 2J emergency bus was paralleled with the F transfer bus and the #3 EOG was secured at 2:11 The lH emergency bus was paralleled with the F transfer bus and the #1 EOG was secured at 4:04 p.m.; thereby, restoring the electrical distribution system to the configuration that existed prior to the even The inspectors were in the control room when the momentary loss of power occurre The inspectors independently verified plant status and monitored operator actions immediately following the loss of power to th~ emergency buses and the actions taken to
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restore offsite powe The inspectors verified proper operation of the EDGs subsequent to their automatic loading onto the IH and 2J emergency buses and verified that Electrical Distribution System TS requirements were me The inspectors determined that the operators in the control room exhibited good command and control and properly implemented the abnormal procedures during the even The licensee will submit an LER in accordance with 10 CFR 50.73 describing this even The inspectors will review the licensee's root cause and corrective actions when the LER is complete Component Cooling Heat Exchanger Fouling On October 6 at 8:20 p.m., the RM on the C CCHx alarmed in.aler Subsequent investigation by Operations revealed nothing abnormal and a sample of the SW side of the C CCHx did not indicate any increase in radioactivit The Hx was performance tested to determine operability per procedure l-OSP-SW-004, Measurement of i~acro Fouling Blockage of CCHx, revision This test determined that the C CCHx was inoperable due to reduced SW flo The Hx was declared inoperable at 10:50 p.m., and removed from service for cleanin Prior to declaring the C CCHx inoperable, the A CCHx RM also alarmed in alert at approximately 9:50 During this same time frame the operators determined that CCHx outlet temperatures were increasing along with Unit 2 containment temperature.
The C CCHx was cleaned and returned to service at 12:55 a.m. on October 7, at which time CC temperatures stabilized. Subsequent testing of the A, B, and D CCHxs determined that they were also inoperable due to reduced SW flow The A CCHx was cleaned and returned to service at 5:44 a.m~ on October The Band D CCHxs were also cleaned and returned to service on October Based on the CCHx test results, the licensee determined that all four CCHxs were inoperable from 10:50 p.m. on October 6 until 12:55 a.m. on October 7, when the C CCHx was cleaned and returned to servic TS 3.0.1, which required a unit shutdown within six hours, was entered. After the C CCHx was made operable at 12:55 a.m. on October 7, TS 3.0.1 was exited before a unit shutdown was initiate Initial investigation by the licensee determined that the SW supply had been swapped from the D CW line to the B CW line at 11:51 a.m. on the *day shift and that the B condenser waterbox had been returned to service at 3:32 The licensee initiated a root cause evaluation to determine the cause of the flow blockage and develop corrective actions to prevent recurrenc The licensee plans to issue an LER describing this even The root cause had not been completed at the end of the inspection perio The inspectors will review this item further when the licensee's root cause is issued.
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5 Review of Corrective Actions for PZR Insurge and Outsurge Controls During the February 4, 1995, Unit 2 cooldown, the licensee experienced difficulty in controlling thermal transients on the PZ At the time of the event, there was a bubble in the PZR and degas evolutions were in progres Degassing with a bubble required the RO to balance charging and letdown flows to maintain a relatively constant level in the PZ Difficulty in balancing these flows was determined to be the cause of exceeding TS limits ror PZR heatup rate. This event resulted in a TS violation and is described in detail in IR 50-280, 281/95-0.6 As corrective action for the TS violation, the licensee consulted with an industry group that was working on improving methods for controlling routine startup and shutdown evolution Prior to the September 8 Unit 1 RFO shutdown, the licensee determined that a chemical degas of the RCS would be use This process allowed the PZR to be taken solid sooner in the shutdown/cooldown evolution which provided more schedular flexibility and at the same time reducing PZR thermal transient The inspectors reviewed procedure l-OP-RC-012, RCS Degas Operations, revision 0, which implemented the chemical degas proces The procedure contained appropriate precautions and limitations, as well as, detailed instructions. During the September 1995 Unit 1 RFO shutdown/cooldown, this method was successfully implemented and no unacceptable PZR thermal transients occurre Containment ESF Sump Inspection Prior to closeout of the Unit 1 containment at the end of the RFO, the inspectors toured the containment buildin The inspectors checked the containment ESF sump for foreign materia The grating was in place and no foreign material was note Additionally, the inspectors noted that the condition of the fibrous filters used in the Iodine Removal System were acceptabl The inspectors also verified, prior to unit startup, that the required water seal to prevent containment sump valve thermal pressure locking was present in the containment ESF sum This verification was based on control room containment ESF sump level instrument indicatio Within the areas inspected, no violations or deviations were identifie.
- Maintenance and Surveillance Inspections (62703, 61726, 62705)
During the reporting period, the inspectors reviewed the following maintenance and surveillance activities to assure compliance with the appropriate procedures and TS requirements.
6 MOV COF Testing The inspectors reviewed the MOV COF Testing Results Report, dated September 27, 199 The report was a final summary of the COF testing performed on 17 Unit 1 MOVs during this outag The testing completed the planned COF testing and verification that a COF value of 0.15 was appropriate for use in MOV analyse The inspectors confirmed that as-found test results supported the conclusion that MOV lubrication problems.experienced at North Anna had not occurred u~ Surr Two valves, l-FW-MOV-160B and l-SI-MOV-186JA, with as-found COF values of 0.165 and 0.190, respectively, were considered as test failures. Actuator disassembly and inspection revealed that l-FW-MOV-160B had approximately 10% greater stem nut to stem thread engagement than norma In addition, the thread machining operation during stem manufacturing had resulted in some stem thread roughnes The actuator was cleaned, lubricated and reassemble The stem threads were also dresse A similar examination for l-SI-MOV-1860A revealed that the stem nut to stem thread engagement was approximately 40% greater than expected and the presence of several small stem thread burrs and dent The stem was dresse Since the valve actuator had a relatively small thrust margin above that required for valve operation, the licensee decided to replace the SMB-000 actuator with a SMB-00 actuator. A similar modification was performed to l-SI-MOV-1860B which had the expected stem nut to stem thread engagement and a 0.105 as-found COF test valu Subsequent testing verified that the COF values for l-FW-MOV-1608 and l-SI-MOV-1860A and B were less than 0.1 The inspectors concluded that the deficiencies discovered during COF testing were properly addresse During data review, the inspectors noted that the valves tested did not repres~nt all possible combinations of ste~ :~zes and valve manufacturer This observation was discussed with cognizant regional personnel who indicated that COF testing for each stem size by valve manufacturer was not necessar The sample size and the appropriateness of the valves chosen will be further reviewed as part of the close out inspection for GL 89-10, Safety Related Motor-Operated Valve Testing and Surveillanc Electrical Maintenance - SBO Diesel Verification Test The AAC DG provides the power source for onsite electrical loads during SBO condition DCP 92-052-3, AAC DG Installation, Surry Units 1 and 2, revision 0, in~talled the equipmen In accordance with the licensee's SBO commitment, document~d in Virginia Power letter 92-292 to the NRC dated May 10, 1993, the licensee performed a special one-time demonstration test of the AAC DG capability. This test verified for Unit 1, the AAC DG ability to accept Unit 1 electrical loads within 10 minutes of the
determination that an SBO condition existed. This capability included starting the AAC DG and completing the electrical alignment to energize the lJ emergency bu The inspectors reviewed the verification test procedure and the completed AAC DG post modification test documentatio Additionally, the conduct of the verification test was observed and test problem resolution activity was reviewed to verify the test activities met the requirements of RG 1.155, Station Blackou The inspectors reviewed test procedure FDTP 92-052-3-6, AAC DG Installation Test, revision 0, to verify appropriate test instructions and acceptance criteria were specifie The procedure provided detailed instructions for equipment operation, establishing initial conditions, precautio~s, *and designation of responsibilities for monitoring and communication Appropriate sign-offs were provided to assure indicated actions were performe The inspectors concluded that the test procedure provided adequate guidance for this special test activit The inspectors re~iewed post modification test documentation for the previously completed testing which verified the four-hour 100 percent load capacity of the AAC DG and the generator control and interlock logic functio FDTP 92-052-3-3, AAC DG Installation Test, revision 0, was performed on June 21, 1995, and verified the four hour capacity. A test anomaly related to cylinder exhaust temperature monitoring was identified and adequately resolve FDTP 92-052-3-2, AAC DG Installation Test, revision 0, was performed on September 15, 1995, and verified the logic function of starting the AAC DG and energizing the AAC DG 4160 V bus on an SBO signa The inspectors concluded that the tests adequately verified the AAC DG capacity and starting logi The inspectors observed the test which verified the 10 minute response capability and AAC DG response to loading of a large pum The test was initiated on September 27, 199 The licensee's pretest briefing of operators and involved test personnel adequately addressed plant conditions and test evolution The initial portion of the test included phase rotation and synchronization checks of the breaker alignment from the lJ emergency bus to the AAC DG 4160 V bu The inspectors observed appropriate personnel and equipment safety precautions and adherence to test procedure steps sequenc The test was discontinued when a problem was identified with the breaker communication network that provided the permissive signal to allow manual closure of the control panel breakers to energize the lJ emergency bus from the AAC D A defect in the fiber optic communication network resulted in intermittent loss of the signal which communicated the condition of the D transfer bus to the programmable controller in the AAC DG control pane The defect impacted the design capability of the AAC DG to energize the emergency bu DR S-95-2291 was initiated to document the
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proble The test was discontinued pendinq resolution of the proble The breaker communication network defect was identified to be a defective modem which was replace The test was continued on October The inspectors observed that the AAC DG started and was aligned to the lJ emergency bus in less than the specified 10 minute The voltage response during loading was acceptable as evidenced by adequate margin being maintained between the voltage dip and the eme,*gency bus low voltage setpoin The test adequately verified the 10 minute capability for Unit 1 specified in the licensee's SBO commitmen The inspectors concluded that the test evolutions were adequately controlled, communication were appropriate, and overall test conduct was goo Test activities were conducted in accordance with the requirements of RG 1.155. Additionally, the test performance and resolution of a test problem demonstrated good communications between the operations, engineering, and maintenance orgar.i~ation Corrective Actions to Improve Control Rod Reliability The licensee experienced two dropped control rod operating events in May 199 Causal factors and immediate corrective actions were previously documented in NRC IR 50-280, 281/95-0 The inspectors noted that, prior to the May rod control failures, recommended corrective actions from previous rod control RCEs to address the adverse rod control cabinet environment had not been implemented in a timely manne RCE 95-08, Unit 2 Dr~p~~d Rod Event, assessed control rod system performance and identified several corrective actions to improve reliability., The inspectors reviewed RCE 95-08 and maintenance documents, conducted interviews, and observed maintenance activities to assess corrective action implementatio RCE 95-08 identified sixteen corrective actions ~~~:h were grouped into five categories; environmental, circuit card testing, circuit card handling, circuit c~rd replacement, and enhancement Management accepted all sixteen recommendations and CTS items were properly establishe The inspectors verified that responsibility for each item was specifically assigned and observed that corrective actions were being implemented within the CTS specified schedule Rod control cabinet inspections and circuit card testing were performed by the vendor using procedure O-NSID-EIS-85-11, Full Length Rod Control System Maintenance, revision 0, during the Unit 1 RF Testing included fifty spare rod control circuit cards in addition to all installed Unit 1 circuit card The inspectors observed portions of the circuit card testing and reviewed the completed test result The circuit cards were generally in good -condition based on the visual examinatio However, circuit card bench testing identified eight discrepancies which were not evident by visual inspection Each discrepancy
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was repaired with satisfactory retest result The licensee also implemented O-NSD-EIS-95-047, CROM Timing Modification and Verification Testing, revision 0, to address industry concerns regarding a 1993 uncontrolled rod withdrawal at another nuclear facilit *
Maintenance personnel completed several actions to improve their capability to verify circuit card performance prior to on-line installations. Technicians built a circuit card test device and developed procedure O-ICM-RD-001, Rod Control Circuit Card Checkout, revision Technicians now have the ability to conduct testing on regulation, failure detection, and signal processing cards as part of receipt inspection and prior to circuit card*
installation in the rod control cabinet Prior to May 1995, receipt inspections were less comprehensive and were done by warehouse personnel. Technicians identified and corrected four circuit card discrepancies during circuit card receipt inspections for the Unit 1 RF The inspectors reviewed procedure O-ICM-RD-001 and discussed circuit card test device construction with technician The recently developed test methods were consistent with vendor testing practice Prior to June 1995, the rod control cabinets operated in an environment which routinely exceeded the manufacturer's recommended temperatur RCE 95-08 concluded prolonged operation at excessive temperatures could reduce circuit card service lif The inspectors noted that twelve new phase control cards a~d eleven new voltage regulator cards were installed during the RFO to address accelerated aging concern Spot coolers were installed in June as a temporary modification to reduce rod control cabinet temperature The inspectors confirmed that a permanent modification to increase upper switchgear room cooling capacity is schedul~d for installation this Winte In addition, operators are now required to record upper switchgear room temperature each shift. If room temperature exceeds 83 degree~ F, the operator must inform the S$ and initiate a DR to correct the conditio The inspectors determined that licensee actio~; to address the adverse rod control cabinet operating environment were appropriat During the inspection period, maintenance and engineering personnel performed walkdowns of the CROM containment electrical penetrations. All connections were satisfactory and no damage was identified on the cablin The inspectors reviewed the WOs associated with these inspections and.also inspected a limited sample of the electrical penetrations inside containmen The penetrations inspected were not damaged and appeared to be well protecte The inspectors concluded that the licensee had properly implemented several positive initiatives to improve rod control system reliability*.
RCE 95-08 was th8rough and established a
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comprehensive set of corrective actions which management has committed to implemen Although corrective actions are not yet complete, CTS items have been properly established and will be tracked to assure full implementatio PZR Nozzle Leaks On September 12, while performing a tagout on PZR level transmitter 1-RC-LT-1460, an operator noticed a slight boron buildup around the level tap nozzle upstream of isolation valve 1-RC-126 where the nozzle penetrates the PZ This observation indicated a pu~~ible throughwall leak on the PZR penetration. A DR was initiated and on September 13, engineering walkdowns of the nine PZR instrument nozzles identified that another instrument nozzle upstream of 1-RC-130 also appeared to have a throughwall lea There are four nozzles on the upper portion of the PZR and five instrument nozzles on the lower portion of the PZ Both leaking nozzles were on the upper portion of the PZR and ar located in the transition region between the shell and dome of the PZ At the time *of initial discovery, the RCS was depressurized and level was being maintained in the PZ Subsequent to opening the PZR manway, a visual inspection of the two suspect nozzles using a remote camera identified staining inside the PZR under the nozzles apparently originating from inside the nozzle Based on the throughwall indications, the licensee developed DCP 95-036 to replace the defective nozzles with components manufactured from 316L stainless steel bar stoc In addition to performing detailed inspections of all four upper nozzles, the licensee also inspected two suspect lower nozzle The inspection consisted of a visual inipection and a liquid penetrate examination conducted from outside the PZ The penetrate examinations conducted on the leaking nozzles revealed a circumferential indication centered at 12 o'clock and extending through an arc of approximately 100 degrees on both nozzle No indications were evident on the other four nozzle The licensee extracted the nozzle upstream of 1-RC-126 from the PZ A detailed metallurgical examination is planned to determine the failure mod With the unit at normal operating pressure, the licensee performed a cursory inspection of the Unit 2 PZR nozzle areas and did not *identity any leakag Insulation was not removed to perform the inspectio The inspectors monitored the actions to identify and repair the leaking PZR nozzles throughout the reporting perio The licensee will submit an LER in accordance with 10 CFR 50.73 describing this even The inspectors will review this item further when the licensee's failure analysis is complet Operation's identification of the suspected RCS leak during tagging evolutions, demonstrated a good questioning attitude.
11 Control Rod Assembly Partial Movement, Procedure 2-0PT-RX-005, revision 5 The inspectors observed the performance of procedure 2-0PT-RX-005, revision 5, Control Rod Assembly Partial Movemen This procedure demonstrates the operability of the control rod assembly drive mechanisms and control circuits. The procedure implements TS 4.1, Table 4.l-2A requirements for quarterly partial movement of all control rod The inspectors observed the procedure being performed on the D rod control ban The evolution was conducted in accordance with the controlling procedure and the control bank met the acceptance criteria c.u11tained in the procedure for operabilit Within the areas inspected, no violations or deviations were identifie.
Engineering Review (37551)
Fuel Failure Review Fuel sipping determined that three Unit 1 cycle 13 fuel assemblies contained fuel rods with failed claddin Visual inspections were unable to determine the exact cause of the failure Although one assembly may have been damaged by debris, the failures were in fuel assemblies that had experienced operating conditions similar to fuel assemblies that had failed during Unit 1 cycle 1 Fuel sipping of Unit 1 cycle 12 fuel assemblies identified four with cladding failure Visual and UT inspections, as well as, some single fuel rod examinations were unable to locate which fuel rod was leaking in the fuel assemblie Thus, no failure mechanism was identifie Oxide measurements revealed approximately 4 or 5 mils more corrosion than anticipated. This 1nformation was incorporated into the Westinghouse corrosion mode Also, the four failed cycle 12 fuel assemblies had experienced similar exposure histories. These fuel as~,~hlies had h 0 en burned twice before being located in the high power regime of the cycle 12 cor Thus, these assemblies had lead rods (the rod with the most burnup) with burnups in the mid-fifty thousand MWD/MTU rang The licensee's evaluation concluded that the high burnup and corrosion rates associated with the Zircaloy-4 cladding had been primary contributors to these cladding failure This information was not available prior to the start of Unit 1 cycle 1 To reduce the potential for fuel failures in Unit 1 cycle 14, twice burned fuel assemblies are being loaded into only low power core iegimes, i.e., only around the core's periphery, and the lead rod burnup in the highest power fuel assemblies will be less than fifty thousand MWD/MT In addition, new fuel assemblies loaded into the core have ZIRLO cladding. Test assemblies with ZIRLO cladding have had measured corrosion rates less than half of that seen with assemblies clad in either Zircaloy-4 or improved Zircaloy-The inspectors agreed that
these actions should reasonably preclude fuel rod failures due to burnup and corrosion during the upcoming Unit 1 cycle 1 Within the areas inspected, no violations or deviations were identifie.
Plant Support (71707, 71750)
lA Station Battery Replacement The licensee has demonstrated increased sensitivity to batt~,y performance since an inuperable station battery event in October 1994 (see NRC IR 50-280, 281/94-32).
RCE 95-03, Batteries, was performed to evaluate an increased number of battery performance problems and battery DRs which were observed during the first half of 199 The inspectors noted that the RCE scope was comprehensive and recommended corrective actions were technically soun The most significant recommendations effec~ed the station batterie The lA und 2A station batteries experienced repeated low cell voltages and electrolyte stratificatio The lA station battery was replaced during the Unit 1 RF The inspectors reviewed purchase order CNT 497969 and various receipt documents for the replacement Class IE type GN-23 battery cell Receipt documentation was complete and included successful factory performance and seismic testing documentation.
Procedure 1-EPT 0106-06, Main Station Battery IA Refueling Performance Test, revision 3, was performed as a post installation tes The inspectors reviewed the test results with the system enginee The battery successfully demonstrated 100 percent design capacity and met the requirements of TS 4.6. The inspectors noted that the most significant cause of the repeated station battery DRs was the limited effectiveness of equalizing charges as a corrective maintenanc Equalization charge voltage has been limited due to DC bus limitations. The vendor recommends a higher equalizing charge voltage than is currently being use Engineers have recommended two actions to address this limitatio The first action requires the station battery to be open circuited and connected to a portable charger strong enough to charge the entire 60 cell battery to the peak vendor recommended voltage (2.42 volts per cell). A periodic PM would be established to perform this charge during RFOs as neede The second action involves individual celi charges which can be performed at manufacturer recommended voltages while the station battery is in servic The licensee has observed limited success using the individual cell charges alon The system engineer informed the inspectors that plant modifications to support doing the elevated voltage equalizing charge are ahead of schedul Unit 1 battery room wall penetrations for charging cable connections were installed during the Unit 1 RF The current schedule indicates that modifications to support the elevated voltage equalizing charge will be complete on both units by the end of 199 The inspectors reviewed CTS item tracking for all RCE 95-03 recommendation Each recommendation was accepted by
management and was on schedul The inspectors concluded that licensee actions to address battery degradation were appropriat Within the areas inspected, no violations or deviations were identifie.
TB Flooding (93702)
On September 14, flooding was reported in the Unit 1 T The inspectors responded to the TB basement in order to assess the extent of the even Unit 1 w~s.in CSD during the event. During preparation for inspections and maintenance on the C 96-inch CW inlet 1 ine, water entered Unit 1 TB basement via open 30-inch manways on the 96-inch CW and 48-inch SW line The previously dewatered C HL bay was found filling with wate Crews responded by installing an additional sump pump at the C HL bay, pumps in the TB basement were operated, and the 30-inch manway covers were reinstalle The licensee conducted a category 2 RCE to determine the causes of the even The RCE assembled the following information:
Stop logs were installed in the A, C, and D HL bays and all three HL bays had been dewatered prior to the even The B 96-inch intake was open and supplying SW to the CCHx The 96-inch blanks were installed in A and C bay The 30-inch manways on the A and C headers were removed in the TB basement to allow access for inspections and repair Four four-inch hydraulic submersible sludge pumps were available at the H One was installed in each of the A, C, and D bays, with one spare. These type pumps are variable speed and are throttled to maintain a minimum water level in the HL bay At 5:00 a.m. on September 14, C HL north bay was reported dry and C south bay had 12 to 18-inches of wate A hydraulic sump pump was running in the sump in the north side of the C HL, maintaining the bay dr A water level is normally present in the south bay of the C H The water normally spills over and collects in the sump This observation was considered normal inleakage past the stop log The C 96-inch line in the TB basement was previously pumped down, via the opened manway, on night shift September 1 The 48-inch header manway was removed following pump dow At approximately 7:40 a.m. on September 14, TB craft were dewatering the A heade Personnel observed one to two feet of water in the C 96-inch pipe at the manwa This appearance of water did not alert the crew that any required corrective actions were necessar They did not know the level of the previous shift's dewatering operation of the C heade Between 8:15 a.m. and 8:30 a.m., TB craft observed the water level to be within one to two inches of the top of the pipe at the C 96-inch line manway in the TB basemen The foreman was notified of
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a potential problem and instructed the TB crew to install a prestaged electric pump in the C manwa The foreman went to the HLIS to verify that the C hydraulic sludge pump was operatin At 8:40 a.m., the foreman informed personnel at the HLIS of the rising water level in the TB C 96-inch lin He instructed personnel at the HLIS to relocate the hydraulic sludge pump from the D bay to C bay to assist in pumping down the C ba At 9:00 a.m., perscmnel at the HUS observed the water level was I-inch to 2-inches from the top of the 96-inch '.lank and rising rapidl The TB crew reported the electric pump was not keeping up with water inflo At this point, water started coming out of the open 30-inch manways on the C 96-inch and 48-inch headers and running onto the floo At 9:17 a.m., the control room was notified of water on the floor in the T Operations dispatched operators to investigat Operations initiated AP-1 All personnel associated with the 96-inch line and HLIS work areas were accounted fo The RCE determined that the root cause of the event was equipment performanc Desigh of the J-seal on the stop logs was questioned and is being reviewed by Engineerin There were several contributing causes to the event as wel They included lack of procedural controls for installing the 96-inch blank at the HL and the need for a HL flood-watch for future activities. Procedures are currently being developed to resolve these concern Completion of procedure implementation and J-seal design review is being tracked by the licensee:s CT The RCE associated with the September 14 TB flooding event, performed by the line organization, represented a commitment to identi1y d11d correct conditions which represent a high risk for core damag Within the areas inspected, no violations or deviations were identifie.
DR Review (40500)
The inspectors reviewed ten DRs issued at the beginning of the RFD to verify that equipment problems were being properly addresse Specifically, the inspectors reviewed the proposed or actual corrective actions for DR S~95-2050, 2051, 2053-2059 and 2061 which were originated on September 9 and 1 The inspectors verified that WOs were issued when required and these WOs were either performed or planned to be completed prior to the end of the RFO if necessary, i.e., work that could only be performed.while the unit was shutdown was not being deferre Based on this sample, emergent equipment problems were being satisfactorily addressed.
Within the areas inspected, no violations or deviations were identifie.
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Action on Previous Inspection Items (92701, 92901, 92902, 92903) (Closed) IFI 50-280, 281/89-32-04, Resolve Inoperability Problem of Component Cooling Water (CCW) Service Water Radiation Monitor RM-SW-107
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This item addressed a reliability problem with the CCW SW Hx RM The monitors experienced chronic failures due to frequent plugging of the sample line and jamming of the monitors' pumps with debri The interim corrective action was periodic grab sampling and analysis of the syste The permanent corrective action was a design change to install a different type of R The design changes were implemented in 1990 and 199 DCP 89-15-3, Replacement of Rad Monitor RM-SW-107, dated February 28, 1990, and DCP 89-21-3, Installation of RM-SW-107A, B, and C, dated July 11, 1992, implemented the permanent corrective action The new design used sodium iodine crystal detectors and has provided
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continuous on-line monitoring since installation. The inspectors concluded the CCW SW RM operability problem had been resolve (Closed) IFI 50-280, 281/93-18-01, Followup of License Actions Associated with Surry Station Engineering Tracking Item No. 51353 This item addressed Appendix R Fire Protection Program compliance issues initially identified at North Anna and tracked at Surry via CTS Item No. 5135 The compliance issues were related to the licensee's commitments to NRC BTP 9.5-1 Appendix A guidelines and their incorporation into the licensee's Fire Protection Progra For example, the implementing Fire Protection Program documents did not include program administrative requirements specified in BTP 9.5-1 such as.the designation of overall program ownership and personnel functional responsibilitie The licensee identified a similar finding in 1994 annual Quality Assurance Fire Protection Audit S94-1 Corrective actions included initiation of studies of Fire Protection Program commitments against program documents to verify implementation of commitment Completion of the studies would then permit licensing actions to remove the Fire Protection Program from the station TS The study to verify the BTP 9.5-1 Appendix A commitments was documented in NES 2791, tracked by CTS Item No. 51353 and completed on June 16, 199 Six discrepancies were identified and resolve The commitments of the Appendix R Safety Evalu~tion Reports were verified in study NES NP-3006, tracked by CTS Item No. 2826, and were completed on May 31, 199 A licensee memorandum from L.T. Warnich, Corporate Fire Protection, to Licensing, dated June 12, 1995, spec1fied that ~he station's actions to remove the Fire Protection Program from the TSs were complet These actions included the verification of applicable commitments into the station Fire Protection Progra The inspectors reviewed VPAP-2401, Fire Protection Program, revision
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1 **, and verified that program ownership and responsibilities were designated. Additionally, the inspectors verified the S94-10 audit findings were resolve The inspectors concluded the Appendix R compliance issues identified by CTS It~m No. 51353 had been resolve (Closed) IFI 50-280, 281/94-30-01, Review the Results of the Design Study of the Turbine Driven Auxiliary Feedwater (TDAFW)
Pump Overspeed Trip Setpoint This item addressed a problem with the reliability of the TDAFW pumps due to a relatively low overspeed trip setpoin The trip point had been lowered in 1991 to 107 percent because the previous 125 percent setpoint permitted pressurization of the downstream piping above the design limit The lowered trip setpoint reduced the margin between the normal operating speed and the overspeed trip condition. Subsequently, several pump trips occurred, usually during pump starting. Root cause investigation determined that a major contributor to the trips was binding of the governor valve due to build up of corrosion ar.d minarals on the valve ste Interim corrective actions included replacement of the valve stem material with chrome plated steel and periodic cleaning and maintenance of the governor valv Since the implementation of the interim actions in August 1994, there have been no additional TDAFW pump trips attributable to governor valve stem bindin Design Study NP-2945, TDAFW Pump Overspeed Trip Evaluation, was initiated to examine a long term resolution and was completed on July 12, 199 The study provided six recommendations including reduction of normal operating speed, reduction of valve stroke, and installing inconel governor valve stem The design change development for these recommendations was approved in the 1996 design budge The inspectors concluded that the interim actions improved TDAFW pump reliability and that the licensee was appropriately addressing TDAFW pump overspeed trip problems. *
Exit Interview The inspection scope and findings were summarized on October 19, 1995, with those persons indicated in paragraph The inspectors described the areas inspected and discussed in detail the inspection results addressed in the summary section and those listed belo Item Number IFI 50-280, 281/89-32-04 Status Closed Description/(Paraqraph No.)
Resolve Inoperability Problem of CCW SW Radiation Monitor RM-SW-107 (paragraph 9.1).
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Item Number IFI 50-280, 281/93-18-0l
Status Closed Description/(Paragraph No.)
Followup of License Actions Associated With Surry Station Engineering Tracking Item N (paragraph 9.2).
IFI 50-280, 281/94-30-01 Closed Review the Results of the Design Study of the TDAFW Pump Overspeed Trip Setpoint (paragraph 9.3).
Proprietary information is not contained in this report. Dissenting comments were not received from the license.
Index of Acronyms AAC DG AC ASME BTP cc CCHx ccw CFR COF CROM
[SD CTS cw DCP DR ECCS EDG ESF FDTP GL HL HLIS Hx IFI IR ISI LER MOV MTU MWD Na NDE NRC PM PRT ALTERNATE AC DIESEL GENERATOR ALTERNATING CURRENT AMERICAN SOCIETY OF MECHANICAL ENGINEtRS BRANCH TECHNICAL POSITION COMPONENT COOLING COMPONENT COOLING HEAT EXCHANGER COMPONENT COOLING WATER CODE OF FEDERAL REGULATIONS COEFFICIENT OF FRICTION CONTROL ROD DRIVE MECHANISM COLD SHUTDOWN COMMITMENT TRACKING SYSTEM CIRCULATING WATER DESIGN CHANGE PACKAGE DEVIATION REPORT EMERGENCY CORE COOLING SYSTEM EMERGENCY DIESEL GENERATOR ENGINEERED SAFETY FEATURE FINAL DESIGN TEST PROCEDURE GENERIC LETTER HIGH LEVEL HIGH LEVEL INTAKE STRUCTURE HEAT EXCHANGER INSPECTOR FOLLOWUP ITEM INSPECTION REPORT INSERVICE INSPECTION LICENSEE EVENT REPORT MOTOR OPERATED VALVE METRIC TONS OF URANIUM MEGAWATT DAXS SODIUM NONDESTRUCTIVE EXAMINATION NUCLEAR REGULATORY COMMISSION PREVENTIVE MAINTENANCE PRESSURIZER RELIEF TANK
PSIG PZR RCE RCP RCS RFO RG RHR RM RO SBO ss SW TB TDAFW TS UT V
VPAP WO
POUNDS PER SQUARE *INCH - GAGE PRESSURIZER ROOT CAUSE EVALUATION REACTOR COOLANT PUMP REACTOR COOLANT SYSTEM REFUELING OUTAGE REGULATORY GUIDE RESIDUAL HEAT REMOVAL RADIATION MONITOR REACTOR OPERATOR STATION BLACKOUT SHIFT SU~tKVISOR SERVICE WATER TURBINE BUILDING TURBINE DRIVEN AUXILIARY FEEDWATER TECHNICAL SPECIFICATION ULTRASOUND TEST VOLTS VIRGINIA POWER ADMINISTRATIVE PROCEDURE WORK ORDER